CHENIERE ENERGY INC - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2004

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 001-16383

CHENIERE ENERGY, INC.

(Exact name as specified in its charter)

Delaware

(State or other jurisdiction of incorporation or organization)

95-4352386

(I.R.S. Employer Identification No.)

717 Texas Avenue, Suite 3100

Houston, Texas

(Address of principal executive offices)

77002

(Zip Code)

(713) 659-1361

(Registrant’s telephone number, including area code)

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 ý No o.

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 o No ý.

As of November 10, 2004, there were 20,201,582 shares of Cheniere Energy, Inc. Common Stock, $.003 par value, issued and outstanding.

CHENIERE ENERGY, INC.

INDEX TO FORM 10-Q

			Page
Part I. Financial Information

	Item 1. Consolidated Financial Statements
		Consolidated Balance Sheet	3
		Consolidated Statement of Operations	4
		Consolidated Statement of Stockholders’ Equity	5
		Consolidated Statement of Cash Flows	6
		Notes to Consolidated Financial Statements	7

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

	Item 3. Quantitative and Qualitative Disclosures About Market Risk		28

	Item 4. Disclosure Controls and Procedures		28

Part II. Other Information

	Item 1. Legal Proceedings		28

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		29

	Item 6. Exhibits		30

CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report contains certain statements that may include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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: statements regarding our business strategy, plans and objectives; statements expressing beliefs and expectations regarding the development of our LNG receiving terminal business; statements expressing beliefs and expectations regarding our ability to successfully raise the additional capital necessary to meet our obligations under our current exploration agreements; statements expressing beliefs and expectations regarding our ability to secure the leases necessary to facilitate anticipated drilling activities; statements expressing beliefs and expectations regarding our ability to attract additional working interest owners to participate in the exploration and development of our exploration areas; and statements about non-historical information. These forward-looking statements are often identified by the use of terms and phrases such as “expect,” “estimate,” “project,” “plan,” “believe,” “achievable,” “anticipate” 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

	September 30, 2004			December 31, 2003
	(Unaudited)
ASSETS

CURRENT ASSETS
Cash and Cash Equivalents	$	7,126,266		$	1,257,693
Restricted Certificate of Deposit	1,128,272			—
Accounts Receivable
Affiliates	—			1,000,000
Other	798,017			1,828,065
Prepaid Expenses	214,306			401,594
Total Current Assets	9,266,861			4,487,352
OIL AND GAS PROPERTIES, full cost method
Proved Properties, net	1,024,793			1,087,152
Unproved Properties, not subject to amortization	18,381,681			18,047,802
Total Oil and Gas Properties	19,406,474			19,134,954
LNG SITE & OTHER RELATED COSTS	534,999			310,500
FIXED ASSETS, net	984,809			578,281
INVESTMENT IN UNCONSOLIDATED AFFILIATE	—			—
INVESTMENT IN LIMITED PARTNERSHIP	84,473			—
DEBT ISSUANCE COSTS	509,180			—
INTANGIBLE LNG ASSETS	80,670			79,670
OTHER	15,910			—
Total Assets	$	30,883,376		$	24,590,757

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts Payable	$	1,145,790		$	1,984,314
Accrued Liabilities	1,748,273			1,347,512
Note Payable	—			1,000,000
Total Current Liabilities	2,894,063			4,331,826
DEFERRED REVENUE	1,000,000			1,000,000
MINORITY INTEREST	288,720			120,032
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: 40,000,000 shares Issued and Outstanding: 19,761,154 shares at September 30, 2004 and 16,488,187 shares at December 31, 2003	59,284			49,465
Additional Paid-in-Capital	72,906,607			48,034,244
Deferred Compensation	(2,553,333		)	—
Accumulated Deficit	(43,711,965		)	(28,944,810		)
Total Stockholders’ Equity	26,700,593			19,138,899
Total Liabilities and Stockholders’ Equity	$	30,883,376		$	24,590,757

The accompanying notes are an integral part of these financial statements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003

Revenues
Oil and Gas Sales	$	465,249		$	135,245		$	1,132,240		$	366,665
Total Revenues	465,249			135,245			1,132,240			366,665

Operating Costs and Expenses
Production Taxes	14,956			—			29,184			—
Depreciation, Depletion and Amortization	265,601			101,003			631,956			251,006
General and Administrative Expenses
LNG Terminal Development	3,334,982			2,343,534			12,664,635			3,360,643
Non-Cash Compensation	438,542			—			2,699,375			—
Other	1,916,300			615,254			5,157,211			1,728,055
General and Administrative Expenses	5,689,824			2,958,788			20,521,221			5,088,698
Total Operating Costs and Expenses	5,970,381			3,059,791			21,182,361			5,339,704

Net Loss from Operations	(5,505,132		)	(2,924,546		)	(20,050,121		)	(4,973,039		)

Equity in Net Income (Loss) of Limited Partnership	(582,798		)	(595,688		)	84,473			(2,655,635		)
Gain on Sale of LNG Assets	—			—			—			4,760,000
Gain on Sale of Limited Partnership Interest	—			—			—			423,454
Reimbursement from Limited Partnership Investment	—			—			2,500,000			—
Interest and Other Income	31,810			1,002			48,283			2,288

Net Loss Before Income Taxes and Minority Interest	(6,056,120		)	(3,519,232		)	(17,417,365		)	(2,442,932		)
Provision for Income Taxes	—			—			—			—
Net Loss Before Minority Interest	(6,056,120		)	(3,519,232		)	(17,417,365		)	(2,442,932		)
Minority Interest	416,831			1,132,211			2,650,210			1,552,978

Net Loss	$	(5,639,289	)	$	(2,387,021	)	$	(14,767,155	)	$	(889,954	)

Net Loss Per Share – Basic & Diluted	$	(0.29	)	$	(0.16	)	$	(0.79	)	$	(0.06	)

Weighted Average Number of Shares Outstanding - Basic & Diluted	19,273,175			15,180,473			18,768,228			14,306,270

The accompanying notes are an integral part of these financial statements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

				Additional									Total
	Common Stock			Paid-In			Deferred			Accumulated			Stockholders’
	Shares	Amount		Capital			Compensation			Deficit			Equity

Balance - December 31, 2002	13,297,393	$	39,892	$	41,414,236		$	—		$	(23,656,793	)	$	17,797,335
Issuances of Stock	2,511,701	7,535		3,899,805			—			—			3,907,340
Issuances of Warrants	—	—		945,049			—			—			945,049
Expenses Related to Offerings	—	—		(57,956		)	—			—			(57,956		)
Net Loss	—	—		—			—			(889,954		)	(889,954		)
Balance - September 30, 2003	15,809,094	$	47,427	$	46,201,134		$	—		$	(24,546,747	)	$	21,701,814

Balance - December 31, 2003	16,488,187	$	49,465	$	48,034,244		$	—		$	(28,944,810	)	$	19,138,899
Issuances of Stock	3,017,634	9,053		22,008,379			—			—			22,017,432
Issuances of Restricted Stock	255,333	766		3,829,234			(3,830,000		)	—			—
Amortization of Deferred Compensation	—	—		—			1,276,667			—			1,276,667
Expenses Related to Offerings	—	—		(965,250		)	—			—			(965,250		)
Net Loss	—	—		—			—			(14,767,155		)	(14,767,155		)
Balance - September 30, 2004	19,761,154	$	59,284	$	72,906,607		$	(2,553,333	)	$	(43,711,965	)	$	26,700,593

The accompanying notes are an integral part of these financial statements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(14,767,155	)	$	(889,954	)
Adjustments to Reconcile Net Loss to Net Cash Used in Operating Activities:
Depreciation, Depletion and Amortization	631,956			251,006
Non-Cash Compensation	2,699,375			—
Equity in Net (Income) Loss of Limited Partnership	(84,473		)	2,655,635
Gain on Sale of LNG Assets	—			(4,760,000		)
Gain on Sale of Limited Partnership Interest	—			(423,454		)
Reimbursement from Limited Partnership Investment	(2,500,000		)	—
Minority Interest	(2,650,210		)	(1,552,978		)
Other	(21,088		)	(3,636		)
Changes in Operating Assets and Liabilities
Accounts Receivable - Affiliates	1,000,000			—
Other Accounts Receivable	(314,205		)	377,746
Prepaid Expenses	126,468			(248,852		)
Accounts Payable and Accrued Liabilities	(781,941		)	95,744
NET CASH USED IN OPERATING ACTIVITIES	(16,661,273		)	(4,498,743		)

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of Fixed Assets	(880,528		)	(210,840		)
Oil and Gas Property Additions	(1,123,932		)	(1,434,161		)
Sale of Interest in Oil and Gas Prospects	1,631,783			391,350
LNG Site and Other Related Costs	(204,553		)	—
Purchase of Intangible LNG Asset	(1,000		)	—
Sale of LNG Assets	—			2,250,000
Reimbursement from Limited Partnership Investment	2,500,000			—
Sale of Limited Partnership Interest	883,333			400,000
Purchase of Restricted Certificate of Deposit	(1,123,094		)	—
NET CASH PROVIDED BY INVESTING ACTIVITIES	1,682,009			1,396,349

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from Issuances of Notes Payable	—			225,000
Repayment of Note Payable	(1,000,000		)	(225,000		)
Sale of Common Stock	20,102,432			2,594,840
Offering Costs	(965,250		)	(57,956		)
Debt Issuance Costs	(108,243		)	—
Partnership Contributions by Minority Owner	2,818,898			1,675,000
NET CASH PROVIDED BY FINANCING ACTIVITIES	20,847,837			4,211,884

NET INCREASE IN CASH AND CASH EQUIVALENTS	5,868,573			1,109,490

CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD	1,257,693			590,039

CASH AND CASH EQUIVALENTS – END OF PERIOD	$	7,126,266		$	1,699,529

The accompanying notes are an integral part of these financial statements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation

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

For further information, refer to the consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2003, as amended. Interim results are not necessarily indicative of results to be expected for the full fiscal year ending December 31, 2004. Certain reclassifications have been made to conform prior period amounts to the current period presentation. These reclassifications have no effect on net income (loss) or stockholders’ equity.

New Accounting Pronouncements

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, Consolidation of Variable Interest Entities, and subsequently revised the Interpretation in December 2003 (FIN 46R). This Interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses consolidation by business enterprises of variable interest entities, which have certain characteristics. As revised, FIN 46R is now generally effective for financial statements for interim or annual periods ending on or after March 15, 2004. We adopted FIN 46R effective January 1, 2004, with no material effect on our consolidated financial statements.

Other Recent Developments

In July 2003, an issue was brought before the FASB regarding whether or not contract-based oil and gas mineral rights held by lease or contract (“mineral rights”) should be recorded or disclosed as intangible assets. The issue presents a view that these mineral rights are intangible assets as defined in Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations,” and, therefore, should be classified separately on the balance sheet as intangible assets. SFAS No. 141 and SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective for transactions subsequent to June 30, 2001, with the disclosure requirements of SFAS No. 142 required as of January 1, 2002. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under the statement, intangible assets should be separately reported on the face of the balance sheet and accompanied by disclosure in the notes to financial statements. SFAS No. 142 does not apply to accounting utilized by the oil and gas industry as prescribed by SFAS No. 19, and is silent about whether or not its disclosure provisions apply to oil and gas companies.

In September 2004, the FASB issued final FASB Staff Position (FSP) FAS 142-2, “Application of SFAS No. 142 to Oil and Gas Producing Entities.” The FSP clarifies that the exception in paragraph 8(b) of SFAS No. 142 includes the balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing entities. Accordingly, the FASB staff believes that the exception extends to the disclosure provisions of SFAS No. 142 for drilling and mineral rights of oil and gas producing entities.

Stock-Based Compensation

We account for employee stock-based compensation granted under our long-term incentive plans using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Stock-based compensation expense associated with option grants was not recognized in the net loss for the three and nine month periods ended September 30, 2004 and 2003, as all options granted had exercise prices equal to the market value of the underlying common stock on the dates of grant. The following table illustrates the effect on the net loss and the net loss per share if we had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation:

		Three Months Ended September 30,						Nine Months Ended September 30,
		2004			2003			2004			2003

Net loss, as reported		$	(5,639,289	)	$	(2,387,021	)	$	(14,767,155	)	$	(889,954	)

Deduct:	Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(567,833		)	(331,164		)	(1,480,246		)	(696,132		)

Pro forma net loss		$	(6,207,122	)	$	(2,718,185	)	$	(16,247,401	)	$	(1,586,086	)

Net loss per share:
Basic and Diluted - as reported		$	(0.29	)	$	(0.16	)	$	(0.79	)	$	(0.06	)
Basic and Diluted - pro forma		$	(0.32	)	$	(0.18	)	$	(0.87	)	$	(0.11	)

Note 2 – Restricted Certificate of Deposit

In connection with our office lease, we are required to provide a letter of credit. On June 23, 2004, we purchased a certificate of deposit in the amount of $1,123,094 (the same amount as the letter of credit) and entered into a pledge agreement in favor of the commercial bank that issued the letter of credit. 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 and accrued interest are classified as restricted on our balance sheet at September 30, 2004. The certificate of deposit matures on November 15, 2004 and bears a fixed interest rate of 1.7% per annum. Through September 30, 2004, $5,178 in interest was accrued for the certificate of deposit.

Note 3 – Investment in Unconsolidated Affiliate

Prior to January 1, 2003, we accounted for our investment in Gryphon Exploration Company (“Gryphon”) using the equity method of accounting because our participation on the Gryphon board of directors provided us with the ability to exercise significant influence over the operating and financial policies of Gryphon. In December 2002, the extent of such influence was diminished when one of the two Cheniere-appointed representatives on the Gryphon board of directors resigned from his position as an officer of Cheniere. Accordingly, effective January 1, 2003, we began accounting for our investment in Gryphon using the cost method of accounting. As of December 31, 2002, Warburg, Pincus Equity Partners, L.P. (“Warburg”) had invested $85,000,000 in Gryphon convertible preferred stock. If Warburg

had converted its investment to common stock as of such date, our ownership interest would have been 9.3%. This effective percent ownership remains unchanged as of September 30, 2004.

As of December 31, 2002, as a result of Gryphon’s cumulative losses and preferred dividend arrearages, our investment in Gryphon was reduced to zero, but not below zero, because we have not guaranteed any obligations of Gryphon, and we are not committed to provide additional financial support to Gryphon.

Note 4 – Investment in Limited Partnership

In August 2002, we entered into an agreement with entities controlled by Michael S. Smith (the “Smith Entities”) to sell a 60% interest in the Freeport LNG receiving terminal site and project. On February 27, 2003, we sold our interest in the site and project to Freeport LNG Development, L.P. (“Freeport LNG”), in which we held a 40% limited partner interest. One of the Smith Entities holds a 60% limited partner interest in Freeport LNG. We recovered $1,740,426 in costs that we had incurred on the project and received an additional $5,000,000 ($2,500,000 during 2003 and $2,500,000 in January 2004) from Freeport LNG. For the funding of Freeport LNG project development costs, the Smith Entities also committed to contribute up to $9,000,000 and to allocate available proceeds from any sales of options or capacity reservations and/or proceeds from loans related to capacity reservations to these costs. In connection with the closing, we issued warrants to one of the Smith Entities to purchase 700,000 shares of Cheniere common stock at a price of $2.50 per share, exercisable for a period of 10 years.

Effective March 1, 2003, we sold a 10% limited partner interest in Freeport LNG to an affiliate of Contango Oil & Gas Company (“Contango”) for $2,333,333 payable over time, including the cancellation of our $750,000 short-term note payable. We also issued warrants to Contango to purchase 300,000 shares of Cheniere common stock at a price of $2.50 per share, exercisable for a period of 10 years. As a result of the sale, we now hold a 30% limited partner interest in Freeport LNG.

We accounted for the transfer of the site and planned LNG receiving terminal to Freeport LNG in accordance with Emerging Issues Task Force Issue No. 01-2, Interpretations of APB Opinion No. 29. Accordingly, in February 2003, we recorded a $4,760,000 gain on the sale of LNG assets to the extent of the 60% interest not retained.

We account for our 30% limited partnership investment in Freeport LNG using the equity method of accounting. During 2003, we received installment payments totaling $2,500,000 from Freeport LNG, which amounts were recorded as a reduction to the basis of our investment in the partnership. In addition, we recorded $4,471,529 related to our 30% equity share of the 2003 net loss of Freeport LNG. This non-cash loss reduced the basis of our investment in Freeport LNG to zero, and as a result, we did not record $278,071 of our equity share of the loss of the partnership as of December 31, 2003.

In January 2004, we received the final $2,500,000 payment from Freeport LNG. As our investment basis in Freeport LNG had been reduced to zero as of December 31, 2003, the payment was recorded as a reimbursement from limited partnership investment in our consolidated statement of operations for the nine months ended September 30, 2004. For the three and nine months ended September 30, 2004, our 30% equity share of net income (loss) from the Freeport partnership was $(582,798) and $84,473 (after deducting the $278,071 loss that was not recorded as of December 31, 2003 discussed above), respectively.

The financial position of Freeport LNG at September 30, 2004 and December 31, 2003 and the results of Freeport LNG’s operations for the three and nine months ended September 30, 2004 and 2003 are summarized as follows (in thousands):

	September 30, 2004			December 31, 2003
	(Unaudited)
Current assets	$	2,493		$	295
Fixed assets, net, and security deposit	164			150
Construction-in-progress	4,746			—
Other long-term assets	609			—
Total assets	$	8,012		$	445

Current liabilities	$	4,046		$	5,887
Deferred revenue	3,500			—
Note payable	6,970			—
Partners’ capital	(6,504		)	(5,442		)
Total liabilities and partners’ capital	$	8,012		$	445

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Revenue	$	3		$	—		$	10,007		$	—
Income (loss) from continuing operations	(1,943		)	(1,993		)	1,208			(8,852		)
Net income (loss)	(1,943		)	(1,986		)	1,208			(8,852		)
Cheniere’s equity in net income (loss) of limited partnership	(583		)	(596		)	84		(1)	(2,656		)

(1) Represents equity in net income for the nine months ended September 30, 2004, less $278,071 equity in loss not recorded as of December 31, 2003.

Note 5 – Debt Issuance Costs

As of September 30, 2004, we had incurred $509,180 of costs directly associated with arranging project debt financing related to the construction of our planned LNG receiving terminals. Such costs are being capitalized and are included in our consolidated balance sheet as of September 30, 2004. These costs are expected to be amortized as interest expense over the term of the loan. If we do not enter into a definitive loan agreement, then these costs will be expensed.

Note 6 - Minority Interest in Limited Partnership

In May 2003, we formed a limited partnership, Corpus Christi LNG, L.P. (“Corpus 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 project, in exchange for a 66.7% interest in Corpus LNG. We also manage the project through the general partner interest held by our wholly-owned subsidiary.

Our consolidated financial statements include the accounts of Corpus LNG. Substantially all Corpus 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 interest owner began sharing all subsequent expenditures based on its 33.3% limited partner interest.

Note 7 – Accrued Liabilities

Accrued liabilities consist of the following:

	September 30, 2004		December 31, 2003
	(Unaudited)

Taxes other than income	$	31,628	$	36,986
LNG terminal development costs	1,202,594		1,183,191
Other accrued liabilities	514,051		127,335
	$	1,748,273	$	1,347,512

Note 8—Deferred Revenue

On December 23, 2003, Cheniere LNG Services, Inc. (“Cheniere LNG Services”), a wholly-owned subsidiary of Cheniere, entered into a shareholders agreement whereby it became a minority owner of J&S Cheniere S.A., a Switzerland joint-stock company (“J&S Cheniere”). We account for this investment using the cost method of accounting. At September 30, 2004, our investment basis was $15,910.

Also on December 23, 2003, Cheniere LNG, Inc. (“Cheniere LNG”), a wholly-owned subsidiary of Cheniere, and J&S Cheniere entered into an option agreement providing J&S Cheniere an option to purchase liquefied natural gas (“LNG”) storage tank capacity and regas capacity of up to 200 million cubic feet per day (“Mmcf/d”) in each of Cheniere LNG’s Sabine Pass and Corpus LNG facilities. Following execution of the option agreement, $1,000,000 was paid by J&S Cheniere to Cheniere LNG in January 2004. The option agreement may be terminated by J&S Cheniere and the option fee refunded in the event that Cheniere LNG does not receive approval from the Federal Energy Regulatory Commission (“FERC”) for at least one of the facilities or if Cheniere LNG decides not to proceed with the development of at least one of the facilities, in either case before December 15, 2005. J&S Cheniere may exercise the option as to each facility by entering into a terminal use agreement no later than 60 days after receipt of written notification by Cheniere LNG that such facility has been approved by FERC and all other approvals and permits have been received which are necessary to begin construction of the facility. Cheniere LNG has recorded the option fee as deferred revenue, and it is anticipated that the option fee will be recognized as revenue over the initial five-year period of the terminal use agreement contemplated by the option agreement.

Note 9 – Note Payable

On June 23, 2004, we terminated our line of credit with a commercial bank. This facility was originally established on July 25, 2003 as a $5,000,000 line of credit, with a borrowing base of $2,000,000. During 2003, we borrowed $1,000,000 under the facility to acquire oil and gas leases. The balance was repaid in January 2004.

Note 10 – Non-Cash Transactions

On February 2, 2004, under the Cheniere Energy, Inc. 2003 Stock Incentive Plan (the “2003 Stock Incentive Plan”), 383,000 shares of common stock were issued to employees and outside directors in the form of bonus and restricted stock awards. We recorded $1,915,000 of non-cash compensation in February 2004 related to the issuance of 127,667 shares (bonus stock awards) valued at $15.00 per share, which shares were fully vested on the date of grant. In addition, we recorded $3,830,000 of deferred compensation as a reduction to stockholders’ equity related to the issuance of 255,333 shares (restricted stock awards) valued at $15.00 per share on the grant date that vests on each of the first and second anniversaries of the grant date. As of September 30, 2004, $1,276,667 of deferred compensation had been amortized.

In August 2003, we issued 378,308 shares of common stock in exchange for the surrender of warrants to purchase 700,000 shares in a cashless transaction.

In April 2003, pursuant to a contingent contractual obligation related to our 2001 acquisition of an option to lease the Freeport LNG terminal site, we issued 750,000 shares of Cheniere common stock, valued at $1,312,500 on the date of issuance, to satisfy a closing requirement related to our February 2003 sale of a 60% interest in our Freeport LNG project.

In February 2003, in connection with the sale of a 60% interest in our Freeport LNG project, we issued warrants valued at $540,015 to purchase 700,000 shares of Cheniere common stock to one of the Smith Entities. In connection with the closing of the Freeport transaction, we also issued additional warrants valued at $173,576 to purchase 225,000 shares of Cheniere common stock to LNG consultants for services previously performed for us. In March 2003, in connection with the sale of a 10% interest in the limited partnership, we issued warrants valued at $241,893 to purchase 300,000 shares of Cheniere common stock to Contango, and Contango canceled the $750,000 note previously payable by Cheniere to Contango.

During the nine months ended September 30, 2004, 162,700 and 56,461 shares of Cheniere common stock were issued in satisfaction of cashless exercises of stock options and warrants to purchase 195,062 and 62,500 shares, respectively.

Note 11 – Net Loss Per Share

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

The following table is a reconciliation of the basic and diluted weighted average shares outstanding for the three and nine months ended September 30, 2004 and 2003:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003
Weighted average common shares outstanding:
Basic	19,273,175	15,180,473	18,768,228	14,306,270
Dilutive common stock options (a)	—	—	—	—
Dilutive common stock warrants (b)	—	—	—	—
Diluted	19,273,175	15,180,473	18,768,228	14,306,270

(a) Options to purchase 214,861 shares of common stock were outstanding but not included in the computations of diluted net loss per share for the three months ended September 30, 2003 because the exercise prices of the options were greater than the average market price of the common shares and would be anti-dilutive to the computations. In-the-money options representing 1,572,048 shares and 1,792,500 shares of common stock were not included in the computation of diluted net loss per share for the three months ended September 30, 2004 and 2003, respectively, because they have an anti-dilutive effect to net loss per share. Options to purchase 110,000 and 264,861 shares of common stock were outstanding but not included in the computations of diluted net loss per share for the nine months ended September 30, 2004 and 2003, respectively, because the exercise prices of the options were greater than the average market price of the common shares and would be anti-dilutive to the computations. In-the-money options representing 1,462,048 shares and 1,742,500 shares of common stock were not included in the computation of diluted net loss per share for the nine months ended September 30, 2004 and 2003, respectively, because they have an anti-dilutive effect to net loss per share.

(b) Warrants to purchase 313,750 shares of common stock were outstanding but not included in the computations of diluted net loss per share for the three months ended September 30, 2003 because the exercise prices of the warrants were greater than the average market price of the common shares and would be anti-dilutive to the computations. In-the-money warrants representing 444,167 and 1,502,427 shares of common stock were not included in the computation of diluted net loss per share for the three months ended September 30, 2004 and 2003, respectively, because they have an anti-dilutive effect to net loss per share. Warrants to purchase 492,460 shares of common stock were outstanding but not included in the computations of diluted net loss per share for the nine months ended September 30, 2003 because the exercise prices of the warrants were greater than the average market price of the common shares and would be anti-dilutive to the computations. In-the-money warrants representing 444,167 and 1,323,717 shares of common stock were not included in the computation of diluted net loss per share for the nine months ended September 30, 2004 and 2003, respectively, because they have an anti-dilutive effect to net loss per share.

Note 12 – Commitments and Contingencies

We are party to a technical services agreement and a memorandum of understanding with an engineering, procurement and construction contractor which provide, respectively, for the front-end engineering and design work for two LNG receiving terminals and the development of an estimate for a lump sum turnkey contract (“Turnkey Contract”) with respect to each terminal. Under the terms of the memorandum of understanding, the contractor is to perform certain services, at its cost, in developing

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

	Three Months Ended						Nine Months Ended
	September 30, 2004			September 30, 2003			September 30, 2004			September 30, 2003

Revenues:
LNG Receiving Terminal	$	—		$	—		$	—		$	—
Oil & Gas Exploration and Development	465,249			135,245			1,132,240			366,665
Total	465,249			135,245			1,132,240			366,665
Corporate and Other (1)	—			—			—			—
Total Consolidated	$	465,249		$	135,245		$	1,132,240		$	366,665

Net Income (Loss):
LNG Receiving Terminal	$	(3,674,621	)	$	(1,839,411	)	$	(8,241,688	)	$	638,954
Oil & Gas Exploration and Development	232,678			103,313			636,601			283,162
Total	(3,441,943		)	(1,736,098		)	(7,605,087		)	922,116
Corporate and Other (1)	(2,197,346		)	(650,923		)	(7,162,068		)	(1,812,070		)
Total Consolidated	$	(5,639,289	)	$	(2,387,021	)	$	(14,767,155	)	$	(889,954	)

	September 30, 2004		December 31, 2003
Total Assets:
LNG Receiving Terminal	$	1,416,147	$	2,952,816
Oil & Gas Exploration and Development	19,939,245		20,219,541
Total	21,355,392		23,172,357
Corporate and Other (1)	9,527,984		1,418,400
Total Consolidated	$	30,883,376	$	24,590,757

(1) Includes corporate activities and certain intercompany eliminations.

Note 14 – Subsequent Events

On November 12, 2004, FERC issued the Final Environmental Impact Statement (“FEIS”) for our proposed Sabine Pass LNG receiving terminal. In the FEIS, FERC concluded that the facility, with appropriate mitigating measures as recommended, would have limited adverse environmental impact. We currently anticipate that we will receive FERC approval and complete the permitting process for this terminal by the end of 2004.

On November 9, 2004, our wholly-owned limited partnership, Sabine Pass LNG, L.P. (“Sabine Pass LNG”), received an advance capacity reservation fee payment of $10,000,000 from Total LNG USA, Inc. (“Total”), a subsidiary of Total SA, upon Total’s exercise of its option to proceed to take 1.0 billion cubic feet per day (“Bcf/d”) of LNG regasification capacity at the 2.6 Bcf/d LNG receiving terminal being developed by Sabine Pass LNG in Cameron Parish, Louisiana. Total also delivered a guarantee by Total SA for certain obligations of Total. These transactions were contemplated under a terminal use agreement and omnibus agreement previously entered into by Sabine Pass LNG and Total on September 2, 2004.

The terminal use agreement provides for Total to pay a tariff of $0.32 per million British thermal units (“Mmbtu”), subject in part to adjustment for inflation, for 1.0 Bcf/d of regasification capacity for a 20-year period beginning not later than April 1, 2009. In addition, under the omnibus agreement, if Sabine Pass LNG enters into a new terminal use agreement with a third party, other than Cheniere affiliates, for capacity of 50 Mmcf/d or more, with a term of five years or more, prior to the commercial start date of the

LNG receiving 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 terminal use agreement for the remainder of the term of the Total terminal use agreement.

Because Total has elected to proceed with the transaction, an additional advance capacity reservation fee payment of $10,000,000 will be payable to Sabine Pass LNG upon satisfaction of two conditions: (i) approval by FERC of the pending application to build the Sabine Pass LNG receving terminal; and (ii) confirmation of evidence of the ability to finance construction of the facility. Total has the right to terminate this transaction if these conditions are not satisfied by June 30, 2005.

The capacity reservation fee payments will be amortized over a ten-year period as a reduction of Total’s regasification capacity tariff under the terminal use agreement. As a result, we intend to record the $20,000,000 in advance payments as deferred revenue to be amortized to income over the corresponding ten-year period.

On November 8, 2004, Sabine Pass LNG entered into a terminal use agreement to provide Chevron USA, Inc. (“Chevron USA”), a wholly-owned subsidiary of ChevronTexaco Corporation (“ChevronTexaco”), with 700 Mmcf/d of LNG regasification capacity also at its receiving terminal under development. Additionally, Sabine Pass LNG entered into an omnibus agreement, under which Chevron USA agreed to make advance capacity reservation fee payments and, in addition, agreed to continue to negotiate for Chevron USA to make a $200 million equity investment to acquire a 20% limited partner interest in Sabine Pass LNG. The terminal use agreement and omnibus agreement remain subject to final corporate approvals, including approval by the ChevronTexaco Board of Directors, by December 20, 2004.

The terminal use agreement provides for Chevron USA to pay a tariff of $0.32 per Mmbtu, subject in part to adjustment for inflation, for 700 Mmcf/d of regasification capacity for a 20-year period beginning not later than July 1, 2009. Under the omnibus agreement, Chevron USA has the option, at the same tariff, either to reduce its reserved capacity at the Sabine Pass LNG receiving terminal to 500 Mmcf/d by July 1, 2005 or to increase its reserved capacity to 1.0 Bcf/d by December 1, 2005. ChevronTexaco will guarantee certain Chevron USA obligations under the terminal use agreement.

The omnibus agreement requires Chevron USA to make advance capacity reservation fee payments to Sabine Pass LNG totaling up to $20,000,000, beginning with an unconditional payment of $5,000,000 by November 23, 2004. Except for this $5,000,000 payment, Chevron USA has the right to terminate the terminal use agreement, the omnibus agreement and the transactions under those agreements if final corporate approvals, including approval of ChevronTexaco’s board of directors, is not obtained by December 20, 2004. If the agreements and transactions are not terminated, further advance capacity reservation fee payments will be due – $7,000,000 after ChevronTexaco’s board approval; $5,000,000 after December 20, 2004, conditioned upon both FERC approval of the pending application to build the Sabine Pass terminal and confirmation of evidence of the ability to finance construction of the facility; and $3,000,000 if Chevron USA exercises the option to increase its capacity at the Sabine Pass LNG facility to 1.0 Bcf/d. These capacity reservation fee payments will be amortized over a ten-year period as a reduction of Chevron USA’s regasification capacity tariff under the terminal use agreement. As a result, we intend to record the advance payments, when received, as deferred revenue to be amortized to income over the corresponding ten-year period.

On November 8, 2004, Sabine Pass LNG signed agreements with HSBC Securities (USA) Inc. and SG Corporate & Investment Banking, an arm of Societe Generale, to arrange the $741 million debt component of the project financing for the construction of the Sabine Pass LNG receiving terminal.

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

General

We are engaged primarily in the development of a liquefied natural gas, or LNG, receiving terminal business and related LNG business opportunities centered on the U.S. Gulf Coast. The LNG receiving terminal business consists 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 three limited partnerships that are developing LNG receiving terminals:

• Sabine Pass LNG, in which we own a 100% interest, is developing an LNG receiving terminal near Sabine Pass in Cameron Parish, Louisiana;

• Corpus LNG, in which we own a 66.7% interest, is developing an LNG receiving terminal near Corpus Christi, Texas; and

• Freeport LNG, in which we own a 30% interest, is developing an LNG receiving terminal on Quintana, Island, near Freeport, Texas.

Sabine Pass LNG. Our 100%-owned limited partnership entity, Sabine Pass LNG, is developing an LNG receiving terminal with an anticipated regasification capacity of 2.6 Bcf/d. In November 2004, FERC issued the FEIS (Final Environmental Impact Statement) for our proposed Sabine Pass LNG receiving terminal. In the FEIS, FERC concluded that the facility, with appropriate mitigating measures as recommended, would have limited adverse environmental impact. We currently anticipate that we will receive FERC approval and complete the permitting process for this terminal by the end of 2004, with construction beginning in the first quarter of 2005 and commercial operations commencing in 2008.

On September 2, 2004, Sabine Pass LNG entered into a terminal use agreement to provide Total with 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 (i) an advance capacity reservation fee payment of $10,000,000, and (ii) a guarantee by Total SA of certain Total obligations under the terminal use agreement. Cheniere, Sabine Pass LNG and Total also entered into an omnibus agreement on September 2, 2004, under which the terminal use agreement remains subject to certain conditions described below.

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

Because Total has elected to proceed with the transaction, an additional advance capacity reservation fee payment of $10,000,000 will be payable to Sabine Pass LNG upon satisfaction of two conditions: (i) approval by FERC of the pending application to build the Sabine Pass LNG receiving terminal; and (ii) confirmation of evidence of the ability to finance construction of the facility. Total has the right to terminate this transaction if these conditions are not satisfied by June 30, 2005.

On November 8, 2004, Sabine Pass LNG entered into a terminal use agreement to provide Chevron USA with 700 Mmcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal. Cheniere, Sabine Pass LNG and Chevron USA simultaneously entered into an omnibus

agreement, under which Chevron USA agreed to make advance capacity reservation fee payments and the companies agreed to continue to negotiate for Chevron USA to make a $200 million equity investment to acquire a 20% limited partner interest in Sabine Pass LNG. The terminal use agreement and omnibus agreement remain subject to final corporate approvals, including approval by the ChevronTexaco Board of Directors, by December 20, 2004.

The terminal use agreement provides for Chevron USA to pay a tariff of $0.32 per Mmbtu, subject in part to adjustment for inflation, for 700 Mmcf/d of regasification capacity for a 20-year period beginning not later than July 1, 2009. Under the omnibus agreement, Chevron USA has the option, at the same tariff, either to reduce its reserved capacity at Sabine Pass to 500 Mmcf/d by July 1, 2005 or to increase its reserved capacity to 1.0 Bcf/d by December 1, 2005. ChevronTexaco will guarantee certain Chevron USA obligations under the terminal use agreement.

In November 2004, we entered into agreements with HSBC Securities (USA) Inc., a subsidiary of HSBC Holdings plc, and SG Corporate & Investment Banking, an arm of Societe Generale, to arrange $741 million of non-recourse project debt financing to fund a substantial majority of the Sabine Pass LNG facility’s construction costs.

In December 2003, we entered into an option agreement with J&S Cheniere S.A. (an entity in which we are a minority owner) providing J&S Cheniere with an option to purchase LNG storage tank capacity and regasification capacity of up to 200 Mmcf/d in each of our Sabine Pass and Corpus 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 option agreement may be terminated by J&S Cheniere and the option fee refunded in the event that Cheniere LNG does not receive FERC approval for at least one of the facilities or if Cheniere LNG decides not to proceed with the development of at least one of the facilities, in either case, before December 15, 2005. J&S Cheniere may exercise the option as to each facility by entering into a terminal use agreement no later than 60 days after receipt of written notification by us that such facility has been approved by FERC and all other approvals and permits have been received which are necessary to begin construction of the facility.

Corpus LNG. We own a 66.7% interest in Corpus LNG, which is developing an LNG receiving terminal with an anticipated regasification capacity of 2.6 Bcf/d. We currently anticipate that we will receive FERC approval and complete the permitting process for this terminal by the second quarter of 2005, with construction beginning in the third quarter of 2005 and commercial operations commencing in 2009.

Freeport LNG. Freeport LNG is developing an LNG receiving terminal with an anticipated regasification capacity of 1.5 Bcf/d. We developed this project and then sold a 60% limited partner interest to an affiliate of the general partner of Freeport LNG and a 10% limited partner interest to another unaffiliated party. We continue to own a 30% limited partner interest in Freeport LNG. Freeport LNG has received FERC approval for this terminal. We currently anticipate that construction will begin by the first quarter of 2005, with commercial operations to commence in late 2007.

In June 2003, The Dow Chemical Company (“Dow”) signed an agreement with Freeport LNG for the potential long-term use of the receiving terminal beginning with commercial start-up of the facility in 2007. On March 1, 2004, Freeport LNG and Dow entered into a 20-year terminal use agreement providing

for a firm commitment by Dow for the use of 250 Mmcf/d of regasification capacity. In August 2004, Dow exercised its option under the agreement and committed to an additional 250 Mmcf/d of regasification capacity for a total of 500 Mmcf/d of regasification capacity.

On December 21, 2003, ConocoPhillips and Freeport LNG signed an agreement under which ConocoPhillips would reserve 1.0 Bcf/d of regasification capacity in the Freeport LNG receiving terminal. ConocoPhillips would also obtain a 50% interest in the general partner of Freeport LNG and provide a substantial majority of the financing to construct the facility. Freeport LNG received a non-refundable capacity reservation fee of $10,000,000 from ConocoPhillips in January 2004. The ConocoPhillips transaction closed in July 2004, at which time ConocoPhillips paid Freeport LNG an additional non-refundable $3,500,000 to secure an option on 500 Mmcf/d of additional capacity in the event the terminal is expanded.

We are pursuing additional potential LNG receiving terminal projects and are also engaged, to a lesser extent, in oil and gas exploration, development and exploitation activities in the Gulf of Mexico.

Because we are in the preliminary stage of developing our LNG receiving terminals, substantially all the costs to-date, related to such activities, have been expensed. These costs primarily include professional fees associated with front-end engineering and design work and obtaining FERC approval and other required permitting for the Sabine Pass LNG and Corpus LNG receiving terminals and their related natural gas pipelines. As a result, we are incurring substantial net losses and negative operating cash flow. We anticipate that our LNG terminal construction projects will be financed with project-level debt or equity securities, capital contributions from Cheniere and other limited partners or a combination thereof. We intend to finance our capital contributions to these projects through the issuance of Cheniere equity or debt securities or other Cheniere borrowings.

Our unaudited consolidated financial statements and notes thereto relate to the three-month and nine-month periods ended September 30, 2004 and 2003. These statements, the notes thereto and the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2003, as amended, contain detailed information that should be referred to in conjunction with the following discussion.

Results of Operations—Comparison of the Three-Month Periods Ended September 30, 2004 and 2003

Overview—Our financial results for the three months ended September 30, 2004 reflect a net loss of $5,639,289, or $0.29 per share (basic and diluted), compared to a net loss of $2,387,021, or $0.16 per share (basic and diluted), during the corresponding period in 2003. The major factors contributing to our loss during the third quarter of 2004 were: (1) LNG receiving terminal development expenses of $3,334,982 (which were offset by a $416,831 minority interest in the operations of Corpus LNG), (2) other general and administrative expenses of $1,916,300, and (3) our equity share of the net loss in Freeport LNG of $582,798.

LNG Terminal Development Activities—LNG terminal development expenses were 42% higher in the third quarter of 2004 ($3,334,982) than in the third quarter of 2003 ($2,343,534) primarily as a result of increased LNG employee-related costs and increased development costs related to our Sabine Pass LNG receiving terminal project.

During the third quarter of 2004, we recorded $1,251,745 in terminal development expenses related to the Corpus LNG terminal in which we are the general partner and own a 66.7% limited partner interest. This amount was partially offset by $416,831 related to the minority interest of our 33.3% limited

partner. We also incurred $1,408,000 in direct terminal development expenses during the third quarter of 2004 related to the Sabine Pass LNG terminal, in which we own 100% of the project. In addition, in the third quarter of 2004, we incurred $677,000 (before overhead recovery of $225,000 from Corpus LNG) in LNG employee-related costs. In connection with the expansion of our LNG terminal development business, our employee costs increased, as we expanded our average LNG staff from 5 employees during the third quarter of 2003 to 16 employees during the third quarter of 2004.

During the third quarter of 2003, we incurred $2,343,534 in LNG receiving terminal development expenses. Of this amount, $1,132,211 related to development costs for the Corpus LNG project. However, these costs were entirely offset by the minority interest of our 33.3% limited partner, which provided 100% of the funding for the first $4,500,000 of partnership expenditures. Because partnership expenditures had reached $4,500,000 as of March 31, 2004, the minority owner began sharing in all subsequent expenditures based on its 33.3% limited partner interest. Also during the third quarter of 2003, we incurred $1,196,000 primarily for development expenses related to the Sabine Pass LNG project.

During the third quarter of 2004, our 30% equity share of the loss from Freeport LNG was $582,798 compared to our equity share of the loss of $595,688 for the third quarter of 2003.

Non-Cash Compensation—Non-cash compensation during the third quarter of 2004 is related to restricted stock awards issued in February 2004 to employees and non-employee directors based on Cheniere’s performance in 2003. The value of these restricted shares was recorded as a reduction to stockholders’ equity as deferred compensation to be amortized over two years as vesting occurs. The $438,542 of non-cash compensation (net of $40,208 capitalized as oil and gas property costs) recorded in the third quarter of 2004 is entirely related to the amortization of such deferred compensation.

Other General and Administrative Expenses—Other general and administrative (“G&A”) expenses are primarily related to our general corporate and other activities. These expenses increased $1,301,046, or 211%, to $1,916,300 in the third quarter of 2004 compared to $615,254 in the corresponding quarter in 2003. G&A increased primarily because of the expansion of our business (including increases in our average corporate staff from 5 employees during the third quarter of 2003 to 15 employees during the third quarter of 2004) and increased professional and other fees primarily in connection with securities compliance filings and increased securities registrations. We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities. We capitalized $197,005 (in addition to the $40,208 related to non-cash compensation mentioned earlier) in the third quarter of 2004 compared to $248,000 during the comparable period in 2003.

Depreciation, Depletion and Amortization Expenses—Depreciation, depletion and amortization (“DD&A”) expenses increased $164,598, or 163%, to $265,601 in the third quarter of 2004 from $101,003 in the third quarter of 2003. The increase is primarily related to increased oil and gas DD&A as a result of increased production volumes discussed below and higher depreciation related to increased furniture, fixtures and equipment associated with the expansion of our business.

Oil and Gas Activities—Oil and gas revenues increased by $330,004, or 244%, to $465,249 in the third quarter of 2004 from $135,245 in the third quarter of 2003 as a result of a 201% increase in production volumes (80,488 thousand cubic feet of natural gas equivalent (“Mcfe”) in the third quarter of 2004 compared with 26,725 Mcfe in the third quarter of 2003) and a 13% increase in average natural gas prices to $5.73 per thousand cubic feet (“Mcf”) in the third quarter of 2004 from $5.06 per Mcf in the third quarter of 2003. We produced from an average of 10 wells in the third quarter of 2004 compared to an average of 7 wells in the third quarter of 2003. We incurred little or no production cost in 2003 and 2004 because all of our revenues were generated from non-cost bearing overriding royalty interests. The small

amount of production taxes in 2004 is attributable to our share of production taxes on a producing well located in Texas state waters.

Results of Operations—Comparison of the Nine-Month Periods Ended September 30, 2004 and 2003

Overview—Our financial results for the nine months ended September 30, 2004 reflect a net loss of $14,767,155, or $0.79 per share (basic and diluted), compared to a net loss of $889,954, or $0.06 per share (basic and diluted), during the corresponding period in 2003.

The major factors contributing to our net loss during the first nine months of 2004 were: (1) LNG receiving terminal development expenses of $12,664,635 (which were offset by a $2,650,210 minority interest in the operations of Corpus LNG), (2) non-cash compensation of $2,699,375 related to 2004 stock awards to employees and non-employee directors based on Cheniere’s performance in 2003 and (3) other general and administrative expenses of $5,157,211. These factors were partially offset by a $2,500,000 reimbursement from our limited partnership investment in Freeport LNG.

LNG Terminal Development Activities—LNG terminal development expenses were 277% higher in the first nine months of 2004 ($12,664,635) than in the first nine months of 2003 ($3,360,643). These expenses were significantly higher because we accelerated, beginning in the third quarter of 2003, the schedule of terminal development for our Sabine Pass and Corpus Christi LNG receiving terminals.

During the first nine months of 2004, we recorded $5,135,293 in terminal development expenses related to the Corpus LNG terminal. This amount was partially offset by $2,650,210 related to the minority interest of our 33.3% limited partner. Substantially all expenditures incurred through March 31, 2004 were the obligation of the minority owner, as the minority owner was required to fund 100% of the first $4,500,000 of project expenditures. As project expenditures had reached $4,500,000 by March 31, 2004, the minority owner began sharing all subsequent project expenditures based on its 33.3% limited partner interest. Also during the first nine months of 2004, we incurred $5,617,000 in direct terminal development expenses related to our Sabine Pass LNG terminal, in which we own 100% of the project. In addition, during the first nine months of 2004, we incurred $2,064,000 (before overhead recovery of $675,000 from Corpus LNG) in LNG employee-related costs. In connection with the expansion of our LNG business, our employee costs increased, as we expanded our average LNG staff from 4 employees during the first nine months of 2003 to 14 employees during the first nine months of 2004.

During the first nine months of 2003, we incurred $3,360,643 in LNG receiving terminal development expenses. Of this amount, $1,552,978 related to development costs for the Corpus LNG project. However, these costs were entirely offset by the minority interest of our 33.3% limited partner as discussed above. Also during the first nine months of 2003, we incurred $1,624,000 primarily for development expenses related to the Sabine Pass LNG project.

In February 2003, our Freeport LNG terminal project was acquired by Freeport LNG in which we received a 40% limited partnership interest and payments to us totaling $5,000,000 over time. In connection with the sale of LNG assets to Freeport LNG, we reported a gain of $4,760,000. We also sold a 10% interest in Freeport LNG in March 2003 for $2,333,333, resulting in a gain of $423,454. During 2003, we received payments totaling $2,500,000 from Freeport LNG, which were recorded as a reduction to our investment in the partnership. In addition, during 2003 we recorded equity in the 2003 loss incurred by Freeport LNG attributable to our 30% limited partner interest, which reduced our investment basis to zero as of December 31, 2003. In January 2004, we received the final $2,500,000 payment from Freeport LNG. Because our investment basis in Freeport LNG had been reduced to zero, the payment was recorded

as a reimbursement from limited partnership investment in our consolidated statement of operations for the nine months ended September 30, 2004.

During the first nine months of 2004, our 30% equity share of net income from Freeport LNG was $84,473, after deducting $278,071 of loss that was not recorded as of December 31, 2003. This compares to our equity share of the loss of $2,655,635 for the first nine months of 2003. The significant improvement from a loss to net income between periods for Freeport LNG was a result of Freeport LNG’s receipt of a non-refundable capacity reservation fee of $10,000,000 from ConocoPhillips in January 2004, upon the delivery of specific engineering and design studies.

Non-Cash Compensation—Non-cash compensation of $2,699,375 (net of $492,292 capitalized as oil and gas property costs) incurred during the first nine months of 2004 resulted from bonus and restricted stock awards issued in February 2004 to employees and non-employee directors based on our performance in 2003. We expensed non-cash compensation in February 2004 related to the issuance of 127,667 shares (bonus stock awards) valued at $15.00 per share, which shares were fully vested on the date of grant. In addition, we have recorded non-cash compensation related to eight months amortization of restricted stock awards previously recorded as deferred compensation and amortizable over two years as vesting occurs.

Other General and Administrative Expenses—Other G&A expenses primarily relate to our general corporate and other activities. These expenses increased $3,429,156, or 198%, to $5,157,211 in the first nine months of 2004 compared to $1,728,055 in the first nine months of 2003. The increase in G&A resulted primarily from the expansion of our business (including increases in average corporate staff from 5 employees during the first nine months of 2003 to 14 employees during the first nine months of 2004) and increased professional and other fees incurred in connection with securities compliance filings and securities registrations. We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities. We capitalized $720,908 (in addition to the $492,292 related to non-cash compensation mentioned earlier) in the first nine months of 2004 compared to $728,000 during the comparable period in 2003.

Depreciation, Depletion and Amortization Expenses—DD&A expenses increased $380,950, or 152%, to $631,956 in the first nine months of 2004 from $251,006 in the first nine months of 2003. The increase primarily resulted from higher oil and gas DD&A as a result of greater production volumes discussed below and also from more depreciation expense resulting from the acquisition of furniture, fixtures and equipment associated with the expansion of our business.

Oil and Gas Activities—Oil and gas revenues increased by $765,575, or 209%, to $1,132,240 in the first nine months of 2004 from $366,665 in the first nine months of 2003 as a result of a 195% increase in production volumes (194,328 Mcfe in the first nine months of 2004 compared with 65,900 Mcfe in the first nine months of 2003) and a 4% increase in average natural gas prices to $5.82 per Mcf in the first nine months of 2004 from $5.57 per Mcf in the first nine months of 2003. We produced from an average of 10 wells in the first nine months of 2004 as compared with an average of 6 wells in the first nine months of 2003. We incurred little or no production cost in 2003 and 2004 because all of our revenues were generated from non-cost bearing overriding royalty interests. The small amount of production taxes in 2004 is attributable to our share of production taxes on a producing well located in Texas state waters.

Liquidity and Capital Resources

LNG Terminal Development

We are primarily engaged in developing LNG receiving and regasification terminals. These LNG terminal development projects will require very significant amounts of capital and, even if successfully completed, will not begin to generate significant cash flows for several years. As a result, our business

success will depend to a significant extent upon our ability to obtain the funding necessary to construct these LNG terminals, to bring them into operation on a commercially viable basis and to finance the costs of staffing, operating and expanding our company during that process.

We own interests in three announced LNG terminal development projects — a 100% interest in Sabine Pass LNG, a 66.7% interest in Corpus LNG and a 30% interest in Freeport LNG. We currently estimate that, in the aggregate, these three terminal projects will require in excess of $2.1 billion to construct and place in service. In addition, we have other potential additional terminal and pipeline projects in different stages of development. These projects, if successfully pursued, will require comparable amounts of capital.

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

As of September 30, 2004, we had working capital of $6,372,798. In November 2004, we received an advance payment of $10,000,000 from Total and expect to receive $5,000,000 that Chevron USA is obligated to pay us on or prior to November 23, 2004, for capacity reservations at the Sabine Pass facility under agreements through which we will receive an additional $10,000,000 from Total and an additional $15,000,000 from Chevron USA if specified conditions are satisfied. We must augment these sources of cash with significant additional funds in order to carry out our business plan.

We currently expect that capital requirements for our three 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 financing plans and anticipated capital requirements for our three current LNG terminal development projects follow.

Sabine Pass LNG. We currently estimate that the cost of constructing the Sabine Pass LNG receiving terminal facility will be approximately $750 million to $850 million, before financing costs. We entered into agreements with HSBC Securities (USA) Inc. and SG Corporate & Investment Banking to arrange $741 million of non-recourse project debt financing to fund a substantial majority of these construction costs. In addition, we are negotiating with Chevron USA to make a $200 million equity investment in Sabine Pass LNG in exchange for a 20% limited partner interest. There is no assurance that we will reach definitive agreements for the proposed project debt financing or the proposed Sabine Pass LNG limited partner equity investment. If we are unable to complete either of these financing arrangements, we will be required to seek alternative sources of financing, which may not be available on acceptable terms, if at all.

Total has paid Sabine Pass LNG an advance capacity reservation fee of $10,000,000 in connection with the reservation of 1.0 Bcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal. An additional advance capacity reservation fee payment of $10,000,000 will be payable to Sabine Pass LNG upon satisfaction of certain conditions described above. The capacity reservation fee payments will be amortized over a ten-year period as a reduction of Total’s regasification capacity tariff under the terminal use agreement. As a result, we intend to record the $20,000,000 in advance payments, though non-refundable, as deferred revenue to be amortized to income over the corresponding ten-year period.

Chevron USA is obligated to pay Sabine Pass LNG an unconditional advance capacity reservation fee of $5,000,000 by November 23, 2004. If the agreements and transactions are not terminated, further

advance capacity reservation fee payments will be due – $7,000,000 after ChevronTexaco’s board approval; $5,000,000 after December 20, 2004, conditioned upon both FERC approval of the pending application to build the Sabine Pass receiving terminal and confirmation of evidence of the ability to finance construction of the facility; and $3,000,000 if Chevron USA exercises the option to increase its capacity at Sabine Pass to 1.0 Bcf/d. These capacity reservation fee payments will be amortized over a ten-year period as a reduction of Chevron USA’s regasification capacity tariff under the terminal use agreement. As a result, we intend to record the advance payments, though non-refundable, as deferred revenue to be amortized to income over the corresponding ten-year period.

In January 2004, we were paid $1,000,000 by J&S Cheniere in connection with an option to purchase LNG storage tank capacity and regasification capacity in each of our Sabine Pass and Corpus LNG facilities. We have recorded the option fee as deferred revenue, and it is anticipated the option fee will be recognized as revenue over the initial five-year period of the terminal use agreement contemplated by the option agreement.

Corpus LNG. We currently estimate that the cost of constructing the Corpus Christi facility will be approximately $650 million to $750 million, before financing costs. The minority owner was required to fund 100% of the first $4,500,000 of Corpus LNG’s expenditures, which amount was reached as of March 31, 2004. Since that date, we have funded 66.7% of the expenditures of Corpus LNG, with the minority owner funding the balance. We currently expect to finance the construction cost of the Corpus Christi terminal in similar manner as the Sabine Pass facility, with a combination of debt project financing and capital contributions by partners. We plan to finance future capital contributions through equity or debt offerings or borrowings by Cheniere. 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.

Freeport LNG. We developed the Freeport LNG project and received cash proceeds of approximately $9,073,759 in connection with the disposition of a 60% limited partner interest to an affiliate of the general partner of Freeport LNG and the disposition of a 10% limited partner to another unaffiliated party.

We currently estimate that the cost of constructing this facility will be approximately $650 million to $750 million, before financing costs. ConocoPhillips has agreed to provide a substantial majority of the financing to construct this facility. ConocoPhillips has also paid Freeport LNG an aggregate of $10,000,000 in connection with the reservation of 1.0 Bcf/d of LNG regasification capacity at the terminal and $3,500,000 for options on 500 Mmcf/d of additional capacity in the event the terminal is expanded.

Under the limited partnership agreement of Freeport LNG, development expenses of the Freeport LNG project generally are to be funded out of Freeport LNG’s own cash flows and by its 60% limited partner. We have not been called upon to contribute any cash to Freeport LNG for development activities. However, we have been advised by the general partner that it plans to expand the capacity of the Freeport facility. We expect that a portion of the funding for this proposed capacity expansion will be made through calls upon us and the other limited partners in Freeport LNG to contribute additional capital. In the event of each such 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, out of future Freeport LNG cash flows otherwise distributable to us. We currently expect to meet these capital calls using cash on hand, revenues from advance capacity reservation fees and funds raised in the future through the issuance of Cheniere equity or debt securities or other Cheniere borrowings.

Short-term Liquidity Needs

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

• cash balances;

• collection of receivables;

• issuances of Cheniere debt and equity securities, including issuances of common stock pursuant to exercises by the holders of existing warrants and options;

• LNG receiving terminal capacity reservations fees; and

• sales of prospects generated by our exploration group.

Historical Cash Flows

Net cash used in operations for the nine months ended September 30, 2004 totaled $16,661,275, compared to net cash used in operations of $4,498,743 for the same period in 2003. The increase in cash used in operations was a direct result of the expansion of our LNG receiving terminal business. In the first quarter of 2003, we phased out our direct involvement in developing the Freeport LNG terminal site, but in subsequent periods, we accelerated the development schedule of our Sabine Pass and Corpus LNG receiving terminals. Net cash provided by investing activities was $1,682,009 for the nine months ended September 30, 2004 as a result of the reimbursement from limited partnership investment, sales of our interests in oil and gas prospects and collection of proceeds from the sale of a limited partnership interest, partially offset by oil and gas property and fixed asset additions, LNG site costs and the purchase of the restricted certificate of deposit. Net cash provided by investing activities was $1,396,349 for the nine months ended September 30, 2003 as a result of the sale of LNG assets, a limited partnership interest and interests in oil and gas prospects, partially offset by oil and gas property and fixed asset additions. Net cash provided by financing activities was $20,847,837 for the nine months ended September 30, 2004 and $4,211,884 for the nine months ended September 30, 2003. Net cash provided by financing activities in these periods consisted primarily of private sales of common stock, exercises of warrants and stock options, and partnership contributions by a minority owner, partially offset by repayments of notes payable.

At September 30, 2004, we had working capital of $6,372,798 compared to $155,526 at December 31, 2003. The increase is primarily attributable to the sale of our common stock through a private placement offering in January 2004 and exercises of warrants and stock options that resulted in aggregate net proceeds of $19,137,182. We also received a $2,500,000 payment from Freeport LNG from the sale of a 60% interest in the Freeport LNG project and $2,818,898 in partnership contributions from our Corpus LNG minority owner. Major uses of working capital included $17,821,846 related to LNG terminal development and other general and administrative expenses during the nine months ended September 30, 2004.

Bank Line of Credit

On June 23, 2004, we terminated our $5,000,000 line of credit with a commercial bank. This facility was originally established on July 25, 2003 with a borrowing base of $2,000,000. During 2003, we borrowed $1,000,000 under the facility to acquire oil and gas leases. The balance was repaid in January 2004.

Restricted Certificate of Deposit and Letter of Credit

Under the terms of our office lease, we are required to post a standby letter of credit to be reduced $224,619 per annum over a five-year period. The initial letter of credit amount of $865,142 which

matured on October 24, 2004, was increased to $1,123,094 in April 2004 related to the expansion of our office space. This letter of credit was initially established under the terms of our bank line of credit.

Upon the termination of our bank line of credit on June 23, 2004, we purchased a certificate of deposit in the amount of $1,123,094 and entered into a pledge agreement in favor of the commercial bank that had previously issued the standby letter of credit for $1,123,094. Under the terms of the pledge agreement, the commercial bank was assigned a security interest in the certificate of deposit as collateral for the letter of credit. As a result, the certificate of deposit plus accrued interest is classified as restricted on our balance sheet at September 30, 2004. The certificate of deposit matures on November 15, 2004 and accrues interest at a fixed rate of 1.7% per annum.

On October 25, 2004, both the letter of credit and certificate of deposit were amended to decrease the face amounts by $224,619 to $898,475. The renewed letter of credit matures on November 30, 2005. The certificate of deposit currently matures on November 15, 2004. However, it is anticipated that a new certificate of deposit for the same amount will be purchased at that time with a maturity date of November 30, 2005.

Off-Balance Sheet Arrangements

As of September 30, 2004, we had no “off-balance sheet arrangements” that may have a current or future material affect on our consolidated financial condition or results of operations.

Lease Obligation

On May 11, 2004, we amended our office lease in order to expand our existing office space. The term for the Expansion Space is for five years with an option, subject and subordinate to another tenant’s renewal option, to renew for a term that would coincide with the term of our existing space that terminates January 2014. No rent is payable for the first nine months of the five-year term. Total payments for the remainder of the five-year Expansion Space lease term are $200,292 per year.

Other Matters

New Accounting Pronouncements

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, and subsequently revised the Interpretation in December 2003 (FIN 46R). This Interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses consolidation by business enterprises of variable interest entities, which have certain characteristics. As revised, FIN 46R is now generally effective for financial statements for interim or annual periods ending on or after March 15, 2004. We adopted FIN 46R effective January 1, 2004, with no material effect on our consolidated financial statements.

Other Recent Developments

No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under the statement, intangible assets should be separately reported on the face of the balance sheet and accompanied by disclosure in the notes to financial statements. SFAS No. 142 does not apply to accounting utilized by the oil and gas industry as prescribed by SFAS No. 19, and is silent about whether or not its disclosure provisions apply to oil and gas companies.

In September 2004, the FASB issued final FASB Staff Position (FSP) FAS 142-2, “Application of SFAS No.142 to Oil and Gas Producing Entities.” The FSP clarifies that the exception in paragraph 8(b) of SFAS No. 142 includes the balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing entities. Accordingly, the FASB staff believes that the exception extends to the disclosure provisions of SFAS No. 142 for drilling and mineral rights of oil and gas producing entities.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. Disclosure Controls and Procedures

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

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

PART II. Other Information

Item 1. Legal Proceedings

The Company has been, and may in the future be involved as, a party to various legal proceedings, which are incidental to the ordinary course of business. Management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, as of September 30, 2004, there were no threatened or pending legal matters that would have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuances of Common Stock

In January 2004, we issued 1,100,000 shares of common stock in a private placement to twelve accredited investors for total consideration of $14,850,000, or $13.50 per share. We paid a 6.5% sales commission totaling $965,250, resulting in $13,884,750 of net proceeds received from the offering. The proceeds of the private placement are being used primarily for the development of LNG receiving terminals and for general corporate purposes.

On February 2, 2004, under the 2003 Stock Incentive Plan, 383,000 shares were issued to employees and outside directors in the form of bonus and restricted stock awards related to our overall 2003 performance. We recorded $1,915,000 of non-cash compensation in February 2004 related to the issuance of 127,667 shares (bonus stock awards) valued at $15.00 per share that were fully vested on the date of grant. In addition, we recorded $3,830,000 of deferred compensation as a reduction to stockholders’ equity related to the issuance of 255,333 shares (restricted stock awards) valued at $15.00 per share on the grant date that vests 50% on each of the first and second anniversaries of the grant date. As of September 30, 2004, $1,276,667 of deferred compensation had been amortized.

During the first nine months of 2004, a total of 777,890 shares of common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of $2,059,308. An additional 162,700 shares of common stock were issued in satisfaction of cashless exercises of options to purchase 195,062 shares of common stock. A total of 792,916 shares of common stock were also issued pursuant to the exercise of warrants, resulting in net proceeds of $3,193,124. An additional 56,461 shares of common stock were issued in satisfaction of cashless exercises of warrants to purchase 62,500 shares of common stock.

Stockholder Rights Plan

On October 13, 2004, our Board of Directors adopted the Stockholder Rights Plan in which preferred stock purchase rights will be distributed as a dividend at the rate of one right for each share of common stock of Cheniere held by stockholders of record as of the close of business on November 1, 2004. The Stockholder Rights Plan is designed to deter coercive takeover tactics, including the accumulation of shares in the open market or through private transactions, and to prevent an acquirer from gaining control of Cheniere without offering a fair price to all of our stockholders. The Stockholder Rights Plan was not adopted in response to any specific threat or takeover offer. The rights under the Stockholder Rights Plan will expire on October 14, 2014.

Each Right under the Stockholder Rights Plan will entitle stockholders to buy one unit of a share of preferred stock for $200, the effect of which would be to significantly dilute the holdings of an acquiring person and to substantially increase the cost of acquiring control in a transaction not approved by our board of directors. The rights under the Stockholder Rights Plan generally will be exercisable only if a person or group acquires beneficial ownership of 15% or more of our common stock or commences a tender or exchange offer upon consummation of which the person or group would beneficially own 15% or more of our common stock.

The rights under the Stockholder Rights Plan are intended to enable all stockholders to realize the long-term value of their investment in Cheniere. The rights under the Stockholder Rights Plan will not prevent a takeover attempt, but are intended to encourage anyone seeking to acquire Cheniere to negotiate with the board of directors prior to attempting a takeover.

Item 6. Exhibits

Each of the following exhibits is incorporated by reference or filed herewith:

Exhibit No.		Description

3.1		Certificate of Designation of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K, filed on October 14, 2004 (SEC File No. 001-16383))

4.1		Rights Agreement by and between Cheniere Energy, Inc. and U.S. Stock Transfer Corp., as Rights Agent, dated as of October 14, 2004 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, filed on October 14, 2004 (SEC File No. 001-16383))

10.1.		LNG Terminal Use Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P.

10.2		Omnibus Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG. L.P.

10.3		Guaranty, dated as of November 9, 2004, by Total S.A. in favor of Sabine Pass LNG, L.P.

10.4		LNG Terminal Use Agreement, dated November 8, 2004, between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P.

10.5		Omnibus Agreement, dated November 8, 2004, between Chevron U.S.A., Inc. and Sabine Pass LNG, L.P.

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 of 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

	CHENIERE ENERGY, INC.


	/s/ Craig K. Townsend
	Vice President and Controller (on behalf of the registrant and as principal accounting officer)

	Date: November 12, 2004

Note 1 – Basis of Presentation

Note 2 – Restricted Certificate of Deposit

Note 3 – Investment in Unconsolidated Affiliate

Note 4 – Investment in Limited Partnership

Note 7 – Accrued Liabilities

Accrued liabilities consist of the following:

Note 9 – Note Payable

SIGNATURES