Edgar Filing: CHENIERE ENERGY INC

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2006

¨	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 x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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 May 3, 2006, there were 54,826,009 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	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	30

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44

	Item 4.	Disclosure Controls and Procedures	45

Part II. Other Information

	Item 1.	Legal Proceedings	45

	Item 6.	Exhibits	46

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

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:

•

statements that we expect to commence or complete construction of each of our proposed liquefied natural gas (“LNG”) receiving terminals or our proposed pipelines, or any expansions or extensions thereof, by certain dates, or at all;

•

statements that we expect to receive Draft Environmental Impact Statements or Final Environmental Impact Statements from the Federal Energy Regulatory Commission (“FERC”) by certain dates, or at all, or that we expect to receive an order from FERC authorizing us to construct and operate proposed LNG receiving terminals or proposed pipelines by certain dates, or at all;

•

statements regarding future levels of domestic or foreign natural gas production or consumption or future levels of LNG imports into North America or sales of natural gas in North America, regardless of the source of such information, or the transportation or other infrastructure or prices related to natural gas, LNG or other hydrocarbon products;

•

statements regarding any financing transactions or arrangements, or ability to enter into such transactions, whether on the part of Cheniere or at the project level, including financing arrangements for which we may have received commitment letters;

•

statements relating to the construction of our proposed LNG receiving terminals and our proposed pipelines, including statements concerning the engagement of any engineering, procurement and construction (“EPC”) contractor and the anticipated terms and provisions of any agreement with an EPC contractor, and anticipated costs related thereto;

•

statements regarding any terminal use agreement (“TUA”) or other agreement to be entered into or performed substantially in the future, including any cash distributions and revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total regasification capacity that is, or may become subject to, TUAs or other contracts;

•

statements that our proposed LNG receiving terminals and pipelines, when completed, will have certain characteristics, including amounts of regasification and storage capacities, a number of storage tanks and docks, pipeline deliverability and the number of pipeline interconnections, if any;

•

statements regarding possible expansions of the currently projected size of any of our proposed LNG receiving terminals;

•

statements regarding our business strategy, our business plans or any other plans, forecasts or objectives, any or all of which are subject to change;

•

statements regarding any Securities and Exchange Commission (“SEC”) or other governmental or regulatory inquiry or investigation;

•

statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;

•

statements regarding our anticipated LNG and natural gas marketing activities; and

•

any other statements that relate to non-historical or future information.

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 for the year ended December 31, 2005. 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(in thousands, except share data)


	March 31, 2006			December 31, 2005
	(unaudited)			(as adjusted)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	678,098		$	692,592
Restricted cash and cash equivalents		144,948			160,885
Restricted certificate of deposit		682			676
Advances to EPC contractor		—			8,087
Accounts receivable		3,799			2,912
Derivative assets		9,413			5,468
Prepaid expenses		2,857			843

Total current assets		839,797			871,463

NON-CURRENT RESTRICTED CASH AND CASH EQUIVALENTS		15,234			16,500
PROPERTY, PLANT AND EQUIPMENT, NET		341,695			280,106
DEBT ISSUANCE COSTS, NET		41,297			43,008
INVESTMENT IN LIMITED PARTNERSHIP		—			—
GOODWILL		76,844			76,844
LONG-TERM DERIVATIVE ASSETS		16,943			1,837
INTANGIBLE ASSETS		240			93
OTHER		301			296

Total assets	$	1,332,351		$	1,290,147

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	2,219		$	778
Accrued liabilities		24,512			54,544
Current portion of long-term debt		6,000			6,000

Total current liabilities		32,731			61,322

LONG-TERM DEBT		986,000			917,500
DEFERRED REVENUE		41,000			41,000
LONG-TERM DERIVATIVE LIABILITIES		—			1,682
LONG-TERM ASSET RETIREMENT OBLIGATION		—			102
COMMITMENTS AND CONTINGENCIES		—			—

STOCKHOLDERS’ EQUITY
Preferred stock, $.0001 par value
Authorized: 5,000,000 shares issued and outstanding: none		—			—
Common stock, $.003 par value
Authorized: 120,000,000 shares at both March 31, 2006 and December 31, 2005 issued and outstanding: 54,768,837 shares at March 31, 2006 and 54,521,131 shares at December 31, 2005		165			164
Treasury stock, 24,300 common shares at cost		(932	)		—
Additional paid-in-capital		372,920			375,551
Deferred compensation		—			(9,684	)
Accumulated deficit		(117,099	)		(101,288	)
Accumulated other comprehensive income		17,566			3,798

Total stockholders’ equity		272,620			268,541

Total liabilities and stockholders’ equity	$	1,332,351		$	1,290,147

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

(in thousands, except per share data)

(unaudited)


	Three Months Ended March 31,
	2006			2005
				(as adjusted)
Revenues
Oil and gas sales	$	422		$	737

Total revenues		422			737


Operating costs and expenses
LNG receiving terminal and pipeline development expenses		8,313			5,424
Exploration costs		838			542
Oil and gas production costs		51			56
Depreciation, depletion and amortization		606			205
General and administrative expenses		13,181			4,990

Total operating costs and expenses		22,989			11,217

Loss from operations		(22,567	)		(10,480	)

Equity in net loss of limited partnership		—			(844	)
Derivative gain		761			—
Interest expense		(11,138	)		—
Interest income		9,544			1,793
Other income		176			—

Loss before income taxes and minority interest		(23,224	)		(9,531	)
Income tax benefit		7,413			—

Loss before minority interest		(15,811	)		(9,531	)
Minority interest		—			97

Net loss	$	(15,811	)	$	(9,434	)

Net loss per common share—basic and diluted	$	(0.29	)	$	(0.18	)

Weighted average number of common shares outstanding—basic and diluted		54,217			52,364

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(in thousands)

(unaudited)


	Common Stock			Treasury Stock					Additional Paid-In Capital			Deferred Compensation			Accumulated Deficit			Accumulated Other Comprehensive Income		Total Stockholders’ Equity
	Shares	Amount		Shares		Amount			Additional Paid-In Capital			Deferred Compensation			Accumulated Deficit			Accumulated Other Comprehensive Income		Total Stockholders’ Equity
Balance—December 31, 2005 (as adjusted)	54,521	$	164	—		$	—		$	375,551		$	(9,684	)	$	(101,288	)	$	3,798	$	268,541
Issuances of stock	184		1	—			—			1,162			—			—			—		1,163
Issuance of restricted stock	88		—	—			—			—			—			—			—		—
Reversal of deferred compensation	—		—	—			—			(9,684	)		9,684			—			—		—
Stock-based compensation	—		—	—			—			5,891			—			—			—		5,891
Purchase of treasury stock	—		—	(24	)		(932	)		—			—			—			—		(932	)
Comprehensive income on interest rate swaps	—		—	—			—			—			—			—			13,768		13,768
Net loss	—		—	—			—			—			—			(15,811	)		—		(15,811	)

Balance—March 31, 2006	54,793	$	165	(24	)	$	(932	)	$	372,920		$	—		$	(117,099	)	$	17,566	$	272,620

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(in thousands)

(unaudited)


	Three Months Ended March 31,
	2006			2005
				(as adjusted)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(15,811	)	$	(9,434	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		606			205
Impairment of unproved properties		323			241
Exploration dry holes		240			—
Amortization of debt issuance cost		918			—
Non-cash compensation		5,600			874
Deferred tax benefit		(7,413	)		—
Equity in net loss of limited partnership		—			844
Minority interest		—			(97	)
Non-cash derivative gain		(722	)		—
Other		184			22
Changes in operating assets and liabilities
Accounts receivable		281			(60	)
Prepaid expenses		(2,014	)		(1,290	)
Accounts payable and accrued liabilities		(2,670	)		5,765

NET CASH USED IN OPERATING ACTIVITIES		(20,478	)		(2,930	)


CASH FLOWS FROM INVESTING ACTIVITIES:
LNG terminal and pipeline construction-in-progress		(73,807	)		(6,457	)
Use of (investment in) restricted cash and cash equivalents		17,203			(1,760	)
Advance to EPC contractor		—			(32,347	)
Purchases of fixed assets		(1,655	)		(1,424	)
Investment in limited partnership		—			(1,134	)
Oil and gas property additions		(1,954	)		(293	)
Sale of interest in oil and gas prospects		448			—
Other		(5	)		(294	)

NET CASH USED IN INVESTING ACTIVITIES		(59,770	)		(43,709	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of term loan		(1,500	)		—
Purchase of treasury shares		(932	)		—
Debt issuance costs		(2,978	)		(16,637	)
Sale of common stock		1,164			1,625
Borrowing under Sabine Pass Credit Facility		70,000			—
Other		—			56

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		65,754			(14,956	)

NET DECREASE IN CASH AND CASH EQUIVALENTS		(14,494	)		(61,595	)
CASH AND CASH EQUIVALENTS—BEGINNING OF PERIOD		692,592			308,443

CASH AND CASH EQUIVALENTS—END OF PERIOD	$	678,098		$	246,848

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. 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 for the year ended December 31, 2005. Interim results are not necessarily indicative of results to be expected for the full fiscal year ending December 31, 2006. 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. As discussed below, we changed our method of accounting for investments in oil and gas properties from the full cost method to the successful efforts method of accounting, and as a result, the change in accounting method required that all prior period financial statements be adjusted to reflect the results and balances that would have been reported had we been following the successful efforts method of accounting from inception.

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.

New Accounting Pronouncements

In February 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 155, Accounting for Certain Hybrid Financial Instruments – An Amendment of FASB Statements No. 133 and 140. SFAS No. 155 provides entities with relief from having to separately determine the fair value of an embedded derivative that would otherwise be required to be bifurcated from its host contract in accordance with SFAS No. 133. SFAS No. 155 allows an entity to make an irrevocable election to measure such a hybrid financial instrument at fair value in its entirety, with changes in fair value recognized in earnings. SFAS No. 155 is effective for all financial instruments acquired, issued or subject to a remeasurement event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We believe that the adoption of SFAS No. 155 will not have a material impact on our consolidated financial statements.

In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of Financial Assets – An Amendment to FASB Statement No. 140. Once effective, SFAS No. 156 will require entities to recognize a servicing asset or liability each time they undertake an obligation to service a financial asset by entering into a servicing contract in certain situations. This statement also requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value and permits a choice of either the amortization or fair value measurement method for subsequent measurement. The effective date of this statement is for annual periods beginning after September 15, 2006, with earlier adoption permitted as of the beginning of an entity’s fiscal year provided the entity has not issued any financial statements for that year. We do not plan to adopt SFAS No. 156 early, and do not believe that it will have a material impact on our consolidated financial statements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Change in Method of Accounting for Investments in Oil and Gas Properties

Effective January 1, 2006, we converted from the full cost method to the successful efforts method of accounting for our investments in oil and gas properties. While our primary focus is the development of our LNG-related businesses, we have continued to be involved, to a limited extent, in oil and gas exploration and development activities in the U.S. Gulf of Mexico. We believe, in light of our current level of exploration and development activities, the successful efforts method of accounting provides a better matching of expenses to the period in which oil and gas production is realized. As a result, we believe that the change in accounting method at this time is appropriate. The change in accounting method constitutes a “Change in Accounting Principle,” requiring that all prior period financial statements be adjusted to reflect the results and balances that would have been reported had we been following the successful efforts method of accounting from our inception. The cumulative effect of the change in accounting method as of December 31, 2004 and 2005 was to reduce the balance of our net investment in oil and gas properties and retained earnings at those dates by $18,237,000 and $17,977,000, respectively. The change in accounting method resulted in an increase in the net loss of $219,000, or $0.00 per share (basic and diluted), for the three months ended March 31, 2005 (see Note 17—”Adjustment to Financial Statements – Successful Efforts”). The change in method of accounting has no impact on cash or working capital.

Successful Efforts Method of Accounting

We have elected to follow the successful efforts method of accounting for our oil and gas properties. Under this method, production costs, geological and geophysical costs including the cost of seismic data, delay rentals, costs of unsuccessful exploratory wells, and internal costs directly related to our exploration and development activities are charged to expense as incurred. The costs of property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are initially capitalized when incurred. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we review proved oil and gas properties and other long-lived assets for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or commodity prices. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amount of the properties is written down to their estimated fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures and a risk-adjusted discount rate. Individually significant unproved properties are also periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Depreciation, depletion and amortization of proved oil and gas properties is determined on a field-by-field basis using the unit-of-production method over the life of the remaining proved reserves.

Capitalized Exploratory Well Costs

In April 2005, the FASB issued a FASB Staff Position (“FSP”) No. FAS 19-1, “Accounting for Suspended Well Costs,” which amends FSP No. FAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Under the provisions of the FSP No. FAS 19-1, exploratory well costs continue to be capitalized after the completion of drilling when (i) the well has found a sufficient quantity of reserves to justify completion as a producing well and (ii) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

met, or if an enterprise obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well would be assumed to be impaired, and its costs, net of any salvage value, would be charged to expense. The FSP No. FAS 19-1 provides several indicators that can assist an entity in demonstrating that sufficient progress is being made when assessing the reserves and economic viability of the project.

At March 31, 2006, our suspended well costs for wells on which drilling was completed more than one year ago were $164,000 relating to a single well, an increase of $164,000 since December 31, 2005. There were no suspended well costs charged to expense in the three months ended March 31, 2006.

NOTE 2—Restricted Cash and Cash Equivalents

In February 2005, Sabine Pass LNG, L.P., our wholly-owned subsidiary (“Sabine Pass LNG”), entered into an $822,000,000 credit facility, or the Sabine Pass Credit Facility, with an initial syndicate of 47 financial institutions. Société Générale serves as the administrative agent and HSBC Bank USA, National Association (“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 Phase 1 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 $371,000 held in these accounts as of March 31, 2006 is classified as restricted on our balance sheet.

In August 2005, Cheniere LNG Holdings, LLC, our wholly-owned subsidiary (“Cheniere LNG Holdings”), entered into a $600,000,000 Senior Secured Term Loan (“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. All additional capital contributions contemplated by the Term Loan were funded to Sabine Pass LNG in 2005. Because the accounts are controlled by the collateral agent, our cash and cash equivalent balance of $159,577,000 held in these accounts as of March 31, 2006 is classified as restricted on our consolidated balance sheet. Of this amount, $15,000,000 is classified as non-current due to the timing of certain required debt amortization payments.

NOTE 3—Advances to EPC Contractor

In December 2004, Sabine Pass LNG entered into a lump-sum turnkey EPC contract with Bechtel Corporation (“Bechtel’) to construct the initial phase (“Phase 1”) of the Sabine Pass LNG receiving terminal. 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 Phase 1. 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 was reclassified to construction-in-progress over a twelve-month period. As of March 31, 2006, the remaining balance of the advance was zero.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

NOTE 4—Property, Plant and Equipment

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


	March 31, 2006			December 31, 2005
				(as adjusted)
LNG TERMINAL COSTS
LNG terminal construction-in-progress	$	329,817		$	271,142
LNG site and related costs, net		1,101			1,249

Total LNG terminal costs		330,918			272,391

NATURAL GAS PIPELINE COSTS
Pipeline construction-in-progress		653			—

Total natural gas pipeline costs		653			—

OIL AND GAS PROPERTIES, successful efforts method
Proved		2,570			97
Unproved		600			1,600
Accumulated depreciation, depletion and amortization		(98	)		(57	)

Total oil and gas properties, net		3,072			1,640

FIXED ASSETS
Computers and office equipment		3,938			3,611
Furniture and fixtures		1,264			1,145
Computer software		2,402			1,640
Leasehold improvements		2,023			1,757
Other		72			26
Accumulated depreciation		(2,647	)		(2,104	)

Total fixed assets, net		7,052			6,075

PROPERTY, PLANT AND EQUIPMENT, net	$	341,695		$	280,106

NOTE 5—Investment in Limited Partnership

We account for our 30% limited partnership investment in Freeport LNG Development, L.P. (“Freeport LNG”) using the equity method of accounting. For the three months ended March 31, 2006 and 2005, our equity share of the net loss of the limited partnership was $3,175,000 and $844,000, respectively. Our net loss for the three months ended March 31, 2005 was increased by $844,000, which was our equity share of the net loss of the limited partnership. As of March 31, 2006, our basis of the investment in Freeport LNG was zero, and as a result, we did not record $3,175,000 of our equity share of the loss of the partnership because we did not guarantee any obligations of Freeport LNG and had not committed to provide additional financial support to Freeport LNG at that time. At March 31, 2006 and December 31, 2005, we had cumulative suspended losses of $7,143,000 and $3,968,000, respectively, related to this investment.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

The financial position of Freeport LNG at March 31, 2006 and December 31, 2005, and the results of Freeport LNG’s operations for the three months ended March 31, 2006 and 2005, are summarized as follows (in thousands):


	March 31, 2006			December 31, 2005
Current assets	$	368,341		$	380,615
Construction-in-progress		315,374			246,351
Fixed assets, net, and other assets		9,503			9,309

Total assets	$	693,218		$	636,275

Current liabilities	$	49,366		$	53,533
Notes payable		667,462			595,766
Deferred revenue and other deferred credits		5,747			5,748
Partners’ deficit		(29,357	)		(18,772	)

Total liabilities and partners’ deficit	$	693,218		$	636,275


	Three Months Ended March 31,
	2006			2005
Loss from continuing operations	$	(10,585	)	$	(2,812	)
Net loss	$	(10,585	)	$	(2,812	)
Cheniere’s equity in loss from limited partnership (1)	$	(3,175	)	$	(844	)

(1)	As discussed above, we did not record the $3,175,000 loss in our consolidated financial statements for the three months ended March 31, 2006 because our investment basis was zero.

NOTE 6—Derivative Instruments

Interest Rate Derivative Instruments

In connection with the closing of the Sabine Pass Credit Facility in February 2005, Sabine Pass LNG entered into swap agreements (the “Sabine Swaps”) with HSBC and Société Générale. Under the terms of the Sabine Swaps, Sabine Pass LNG is 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 hedged drawings under the Sabine Pass Credit Facility up to a maximum of $700,000,000, at 4.49% from July 25, 2005 through March 25, 2009 and at 4.98%, from March 26, 2009 through March 25, 2012. The final termination date of the Sabine Swaps is March 25, 2012.

In connection with the closing of the Term Loan on August 31, 2005, Cheniere LNG Holdings 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, Cheniere LNG Holdings hedged an initial notional amount of $600,000,000. The notional amount declines 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 is September 30, 2010.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Accounting for Hedges

SFAS No. 133, 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. In our case, the impact on earnings is a reduction of $710,000 in interest expense for the three months ended March 31, 2006. The ineffective portion of the gain or loss on the derivative instrument, if any, must be recognized currently in earnings. For the three months ended March 31, 2006, we have recognized net derivative gains of $761,000 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.

Summary of Derivative Values

The following table reflects the amounts that are recorded as assets and liabilities at March 31, 2006 for our derivative instruments (in thousands):


	Interest Rate Derivative Instruments
Current derivative assets	$	9,413
Derivative receivables (1)		1,902
Long-term derivative assets		16,943

Total derivative assets		28,258

Current derivative liabilities		—
Derivative payables		—
Long-term derivative liabilities		—

Total derivative liabilities		—

Net derivative assets	$	28,258

(1)	Included in Accounts Receivable on the Consolidated Balance Sheet.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Below is a reconciliation of our net derivative liabilities to our accumulated other comprehensive income at March 31, 2006 (in thousands):


Net derivative asset	$	28,258
Effective non-cash items		(39	)
Ineffective non-cash items		(1,198	)

Accumulated other comprehensive income before income tax		27,021
Income taxes on other comprehensive loss		(9,455	)

Accumulated other comprehensive income after income tax	$	17,566

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 March 31, 2006, $10,539,000 of accumulated net deferred gains on the Swaps, currently included in OCI, are expected to be reclassified to earnings during the next twelve months, assuming no change in the LIBOR forward curves at March 31, 2006. 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 twelve months.

NOTE 7—Accrued Liabilities

Accrued liabilities consist of the following (in thousands):


	March 31, 2006		December 31, 2005
LNG terminal construction costs	$	16,247	$	39,728
Accrued interest expense and related fees		2,053		4,937
Debt issuance costs		—		3,083
Payroll		109		2,460
LNG terminal development expenses		2,831		1,534
Professional and legal services		906		1,043
Pipeline construction costs		228		—
Fixed assets		541		—
Oil and gas assets		698		—
Insurance expense		—		41
Other accrued liabilities		899		1,718

Accrued liabilities	$	24,512	$	54,544

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

NOTE 8—Long-Term Debt

As of March 31, 2006 and December 31, 2005, our long-term debt was comprised of the following (in thousands):


	March 31, 2006			December 31, 2005
Sabine Pass Credit Facility	$	70,000		$	—
Convertible Senior Unsecured Notes		325,000			325,000
Term Loan		597,000			598,500

		992,000			923,500
Less: Current Portion—Term Loan		(6,000	)		(6,000	)

Total Long-Term Debt	$	986,000		$	917,500

Sabine Pass Credit Facility

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 Phase 1 of our 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 could make an initial borrowing under the Sabine Pass Credit Facility, it was required to provide evidence that it had received equity contributions in an amount sufficient to fund $233,715,000 of the project costs. As of December 31, 2005, the $233,715,000 in equity contributions had been funded. At December 31, 2005, there were no borrowings outstanding; however, as of March 31, 2006, $70,000,000 had been drawn 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 agreement and (ii) the commercial start date under the Total LNG USA, Inc. (“Total”) TUA. Sabine Pass LNG may specify an earlier date to commence repayment upon satisfaction of certain conditions. In any event, payments under the Sabine Pass Credit Facility must commence no later than October 1, 2009, and all obligations under the Sabine Pass Credit Facility mature and must be fully repaid by February 25, 2015.

The Sabine Pass Credit Facility contains customary conditions precedent to any borrowings, as well as customary affirmative and negative covenants. We were in compliance, in all material respects, with these covenants at March 31, 2006 and December 31, 2005. Sabine Pass LNG has obtained, and may in the future seek, consents, waivers and amendments to the Sabine Pass Credit Facility documents. The obligations of Sabine Pass LNG under the Sabine Pass Credit Facility are secured by all of Sabine Pass LNG’s personal property, including the TUAs with Total and Chevron USA, Inc. (“Chevron”) and the partnership interests in Sabine Pass LNG.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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 Phase 1 of our Sabine Pass LNG receiving terminal. As of March 31, 2006 and December 31, 2005, $7,387,000 and $5,323,000, respectively, in commitment fees, interest costs, impact of interest rate swaps and amortization of debt issuance costs had been capitalized and included in LNG terminal construction-in-progress, respectively.

Convertible Senior Unsecured Notes

In July 2005, we consummated a private offering of $325,000,000 aggregate principal amount of 2.25% Convertible Senior Unsecured Notes (the “Notes”) due August 1, 2012 to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The Notes are convertible into our common stock pursuant to the terms of the indenture governing the Notes 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 indenture governing the Notes contains customary reporting requirements.

Concurrent with the issuance of the 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 March 31, 2006, no holders had elected to convert their Notes. Total interest expense recognized for the three months ended March 31, 2006 was $2,154,000 before interest capitalization of $241,000.

Term Loan

In August 2005, Cheniere LNG Holdings entered into the $600,000,000 Term Loan with Credit Suisse. The Term Loan has an interest rate equal to LIBOR plus a 2.75% margin and matures on August 30, 2012. In connection with the closing, Cheniere LNG Holdings entered into the Term Loan Swaps with Credit Suisse to hedge the LIBOR interest rate component of the Term Loan. The blended rate of the Term Loan Swaps 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 6—”Derivative Instruments”). On December 30, 2005, Cheniere LNG Holdings made the first required quarterly principal payment of $1,500,000. 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—”Restricted Cash and Cash Equivalents,” a portion of the loan proceeds is controlled by Credit Suisse and is restricted as to its use.

At March 31, 2006, principal repayments on the Term Loan 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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

months ended March 31, 2006 was $11,138,000 before interest capitalization of $1,099,000 and impact of the Term Loan Swaps of $686,000. The Term Loan contains customary affirmative and negative covenants. Cheniere LNG Holdings was in compliance with these covenants, in all material respects, at March 31, 2006. 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.

NOTE 9—Financial Instruments

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.

Long-Term Debt (in thousands):


	March 31, 2006
	Carrying Amount		Estimated Fair Value
Term Loan due 2012 (1)	$	597,000	$	597,000
2.25% Convertible Senior Unsecured Notes due 2012 (2)		325,000		418,236
Sabine Pass Credit Facility (3)		70,000		70,000

	$	992,000	$	1,085,236

(1)	The Term Loan bears interest based on a floating rate; therefore, the estimated fair value is deemed to equal the carrying amount of these notes.

(2)	The fair value of the Notes is based on the closing bid price as of March 31, 2006.

(3)	The Sabine Pass Credit Facility bears interest based on a floating rate.

NOTE 10—Income Taxes

From our inception, we have reported annual net operating losses for both financial reporting purposes and for federal and state income tax reporting purposes. Accordingly, we are not presently a taxpayer and have not recorded a net liability for federal or state income taxes in any of the periods included in the accompanying financial statements. Our consolidated statement of operations for the three months ended March 31, 2006 and 2005 includes deferred income tax benefits of $7,413,000, and $-0-, respectively. The deferred income tax benefit recorded for the three months ended March 31, 2006 has been provided for in accordance with the guidance in paragraph 140 of SFAS No. 109 and EITF Abstracts, Topic D-32, which, in certain circumstances, requires items reported in pre-tax accumulated other comprehensive income to be considered in the determination of the amount of tax benefit when a net operating loss occurs. In our situation, the specific circumstance relates to pre-tax accumulated other comprehensive income of $27,021,000 recorded as of March 31, 2006 related to our interest rate swaps (see Note 6—”Derivative Instruments” for additional discussion). The deferred tax benefit included in our consolidated statement of operations for the three months ended March 31, 2006, represents the portion of the change in our tax asset valuation account that is allocable to the deferred income tax on items reported in accumulated other comprehensive income in our March 31, 2006 consolidated statement of stockholders’ equity.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Income tax benefit included in our reported net loss consists of the following (in thousands):


	Three Months Ended March 31,
	2006		2005
Current federal income tax expense	$	—	$	—
Deferred federal income tax benefit		7,413		—

	$	7,413	$	—

NOTE 11—Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing the net income (loss) by the weighted average number of shares of common stock 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 Cheniere’s earnings.

The following table reconciles basic and diluted weighted average shares outstanding for the three months ended March 31, 2006 and 2005 (in thousands except for loss per share):


	Three Months Ended March 31,
	2006			2005
				(as adjusted)
Weighted average common shares outstanding:
Basic		54,217			52,364
Dilutive common stock options (1)		—			—
Dilutive common stock warrants (1)		—			—
Dilutive Convertible Senior Unsecured Notes (1)		—			—

Diluted		54,217			52,364

Basic loss per share	$	(0.29	)	$	(0.18	)
Diluted loss per share	$	(0.29	)	$	(0.18	)

(1)	Dilutive shares were not included in the calculation, as we had a net loss for the periods ended March 31, 2006 and 2005.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

NOTE 12—Other Comprehensive Loss

The following table is a reconciliation of our net loss to our comprehensive loss for the periods shown (in thousands):


	Three Months Ended March 31,
	2006			2005
				(as adjusted)
Net loss	$	(15,811	)	$	(9,434	)
Other comprehensive income items:
Cash flow hedges, net of tax		13,768			5,006

Comprehensive loss	$	(2,043	)	$	(4,428	)

NOTE 13—Related Party Transactions

From time to time, officers and employees may charter aircraft for company business travel. We entered into a letter agreement, or charter letter, with an unrelated third-party entity, Western Airways, Inc. (“Western”) that specified the terms under which it would provide for charter of a Challenger 600 aircraft. One of the Challenger 600 aircraft which could be provided by Western for such services was 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 were 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 months ended March 31, 2006, we incurred $111,000 related to the charter of the Challenger 600 aircraft owned by the LLC.

NOTE 14—Commitments and Contingencies

In March 2006, Cheniere LNG Services, SARL (“Cheniere LNG Services”), our wholly-owned subsidiary, entered into a 9-year lease for office space in Paris, France. The lease calls for annual payments of approximately $234,000 (based on the Euro exchange rate in effect on March 31, 2006).

NOTE 15—Supplemental Cash Flow Information

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


	Three Months Ended March 31,
	2006		2005
Cash paid during the period for:
Interest (net of amounts capitalized)	$	16,512	$	—
Income taxes	$	—	$	—

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

NOTE 16—Business Segment Information

At this stage in our development, 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 three, 100% owned LNG receiving terminal projects along the U.S. Gulf Coast at the following locations: Sabine Pass LNG in western Cameron Parish, Louisiana on the Sabine Pass Channel; Corpus Christi LNG near Corpus Christi, Texas; and Creole Trail LNG at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. In addition, we own a 30% minority interest in a fourth project, Freeport LNG, located on Quintana Island near Freeport, Texas. Our related natural gas pipeline development activities and other initiatives that complement the development of our LNG receiving terminal business are also presently included in the segment.

Our oil and gas exploration and development segment explores for oil and natural gas using a regional database of approximately 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, through participation in the drilling of wells, and through farm-out arrangements and back-in interests (a reversionary interest in oil and gas leases reserved by us) whereby the capital costs of such activities are borne primarily 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 loss and total assets for each of our operating segments (in thousands):


	Three Months Ended March 31,
	2006			2005
				(as adjusted)
Revenues:
LNG receiving terminal	$	—		$	—
Oil and gas exploration and development		422			737

Total		422			737
Corporate and other (1)		—			—

Total consolidated	$	422		$	737

Net loss:
LNG receiving terminal	$	(11,178	)	$	(6,761	)
Oil and gas exploration and development		(1,184	)		(215	)

Total		(12,362	)		(6,976	)
Corporate and other (1)		(3,449	)		(2,458	)

Total consolidated	$	(15,811	)	$	(9,434	)

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)


	March 31, 2006		December 31, 2005
			(as adjusted)
Total Assets:
LNG receiving terminal	$	841,006	$	783,837
Oil and gas exploration and development		3,291		2,328

Total		844,297		786,165
Corporate and other (1)		488,054		503,982

Total consolidated	$	1,332,351	$	1,290,147

(1)	Includes corporate activities and certain intercompany eliminations.

NOTE 17—Adjustment to Financial Statements – Successful Efforts

As a result of our election to change our method of accounting for investments in oil and gas properties as discussed in Note 1—”Basis of Presentation”, adjustments have been made to the financial statements of prior periods as required by SFAS No. 154, Accounting Changes and Error Corrections. The effects of the change as it relates to financial data for the periods presented are displayed below (in thousands, except per share data):

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Statement of Operations

(Unaudited)


	Three Months Ended March 31, 2006
	As Computed Under Full Cost			As Reported Under Successful Efforts			Effect of Change
Revenues	$	422		$	422		$	—
Operating costs and expenses:
LNG receiving terminal and pipeline development expenses		8,313			8,313			—
Exploration costs		—			838			838
Oil and gas production costs		51			51			—
Depreciation, depletion and amortization		847			606			(241	)
Ceiling test write-down		5,595			—			(5,595	)
General and administrative expenses		13,181			13,181			—

Total operating costs and expenses		27,987			22,989			(4,998	)

Loss from operations		(27,565	)		(22,567	)		4,998
Non-operating loss and minority interest		(833	)		(657	)		176

Loss before income taxes		(28,398	)		(23,224	)		5,174
Income tax benefit		7,413			7,413			—

Net loss	$	(20,985	)	$	(15,811	)	$	5,174

Net loss per share—basic and diluted	$	(0.39	)	$	(0.29	)	$	0.10


	Three Months Ended March 31, 2005
	As Originally Reported			As Reported Under Successful Efforts			Effect of Change
Revenues	$	737		$	737		$	—
Operating costs and expenses:
LNG receiving terminal and pipeline development expenses		5,424			5,424			—
Exploration costs		—			542			542
Oil and gas production costs		56			56			—
Depreciation, depletion and amortization		528			205			(323	)
General and administrative expenses		4,990			4,990			—

Total operating costs and expenses		10,998			11,217			219

Loss from operations		(10,261	)		(10,480	)		(219	)
Non-operating income and minority interest		1,046			1,046			—

Loss before income taxes		(9,215	)		(9,434	)		(219	)
Income tax provision		—			—			—

Net loss	$	(9,215	)	$	(9,434	)	$	(219	)

Net loss per share—basic and diluted	$	(0.18	)	$	(0.18	)	$	—

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Balance Sheet

(Unaudited)


	March 31, 2006
	As Computed Under Full Cost			As Reported Under Successful Efforts			Effect of Change
Current assets	$	839,797		$	839,797		$	—

Oil and gas properties, net		15,875			3,072			(12,803	)
Other property, plant and equipment, net		338,623			338,623			—

Total property, plant and equipment, net		354,498			341,695			(12,803	)

Other non-current assets		150,859			150,859			—

Total assets	$	1,345,154		$	1,332,351		$	(12,803	)

Current liabilities	$	32,731		$	32,731		$	—
Non-current liabilities		1,027,000			1,027,000			—

Common stock		165			165			—
Treasury stock		(932	)		(932	)		—
Additional paid-in capital		372,920			372,920			—
Accumulated deficit		(104,296	)		(117,099	)		(12,803	)
Accumulated other comprehensive income		17,566			17,566			—

Total stockholders’ equity		285,423			272,620			(12,803	)

Total liabilities and stockholders’ equity	$	1,345,154		$	1,332,351		$	(12,803	)


	December 31, 2005
	As Originally Reported			As Adjusted			Effect of Change
Current assets	$	871,463		$	871,463		$	—

Oil and gas properties, net		19,617			1,640			(17,977	)
Other property, plant and equipment, net		278,466			278,466			—

Total property, plant and equipment, net		298,083			280,106			(17,977	)

Other non-current assets		138,578			138,578			—

Total assets	$	1,308,124		$	1,290,147		$	(17,977	)

Current liabilities	$	61,322		$	61,322		$	—
Non-current liabilities		960,284			960,284			—

Common stock		164			164			—
Additional paid-in capital		375,551			375,551			—
Deferred compensation		(9,684	)		(9,684	)		—
Accumulated deficit		(83,311	)		(101,288	)		(17,977	)
Accumulated other comprehensive income		3,798			3,798			—

Total stockholders’ equity		286,518			268,541			(17,977	)

Total liabilities and stockholders’ equity	$	1,308,124		$	1,290,147		$	(17,977	)

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Statement of Cash Flows

(Unaudited)


	Three Months Ended March 31, 2006
	As Computed Under Full Cost			As Reported Under Successful Efforts			Effect of Change
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(20,985	)	$	(15,811	)	$	5,174
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		847			606			(241	)
Ceiling test write-down		5,595			—			(5,595	)
Impairment of unproved properties		—			323			323
Exploration dry holes		—			240			240
Other adjustments		(1,433	)		(1,433	)		—
Changes in operating assets and liabilities		(4,403	)		(4,403	)		—

NET CASH USED IN OPERATING ACTIVITIES		(20,379	)		(20,478	)		(99	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas property additions, net of sales		(1,605	)		(1,506	)		99
Other cash flows from other investing activities		(58,264	)		(58,264	)		—

NET CASH USED IN INVESTING ACTIVITIES		(59,869	)		(59,770	)		99

NET CASH PROVIDED BY FINANCING ACTIVITIES		65,754			65,754			—

NET DECREASE IN CASH AND CASH EQUIVALENTS		(14,494	)		(14,494	)		—
CASH AND CASH EQUIVALENTS—BEGINNING OF PERIOD		692,592			692,592			—

CASH AND CASH EQUIVALENTS—END OF PERIOD	$	678,098		$	678,098		$	—


	Three Months Ended March 31, 2005
	As Originally Reported			As Reported Under Successful Efforts			Effect of Change
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(9,215	)	$	(9,434	)	$	(219	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		528			205			(323	)
Impairment of unproved properties		—			241			241
Other adjustments		1,643			1,643			—
Changes in operating assets and liabilities		4,415			4,415			—

NET CASH USED IN OPERATING ACTIVITIES		(2,629	)		(2,930	)		(301	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas property additions, net of sales		(594	)		(293	)		301
Other cash flows from other investing activities		(43,416	)		(43,416	)		—

NET CASH USED IN INVESTING ACTIVITIES		(44,010	)		(43,709	)		301

NET CASH USED IN FINANCING ACTIVITIES		(14,956	)		(14,956	)		—

NET DECREASE IN CASH AND CASH EQUIVALENTS		(61,595	)		(61,595	)		—
CASH AND CASH EQUIVALENTS—BEGINNING OF PERIOD		308,443			308,443			—

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

NOTE 18—Share-Based Compensation

We have granted options to purchase common stock to employees, consultants and outside directors under the Cheniere Energy, Inc. Amended and Restated 1997 Stock Option Plan (“1997 Plan”) and the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (“2003 Plan”). Prior to January 1, 2006, we accounted for grants made under the 1997 Plan and 2003 Plan using the intrinsic value method under the recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees and related interpretations, and applied SFAS No. 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure, for disclosure purposes only. Under APB Opinion No. 25, stock-based compensation cost related to stock options was not recognized in net income since the options granted under those plans had exercise prices greater than or equal to the market value of the underlying stock on the date of grant.

Effective January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share-Based Payment, which revised SFAS No. 123 and superseded APB No. 25. SFAS No. 123R requires that all share-based payments to employees be recognized in the financial statements based on their fair values at the date of grant. The calculated fair value is recognized as expense (net of any capitalization) over the requisite service period, net of estimated forfeitures, using the straight-line method under SFAS No. 123R. We consider many factors when estimating expected forfeitures, including types of awards, employee class and historical experience. The statement was adopted using the modified prospective method of application, which requires compensation expense to be recognized in the financial statements for all unvested stock options beginning in the quarter of adoption. No adjustments to prior periods have been made as a result of adopting SFAS No. 123R. Under this transition method, compensation expense for share-based awards granted prior to January 1, 2006, but not yet vested as of January 1, 2006, and not previously amortized through the pro forma disclosures required by SFAS No. 123, will be recognized in our financial statements over their remaining service period. The cost was based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123. As allowed by SFAS No. 123, compensation cost associated with forfeited options was reversed for disclosure purposes in the period of forfeiture. As required by SFAS No. 123R, compensation expense recognized in future periods for share-based compensation granted prior to adoption of the standard will be adjusted for the effects of estimated forfeitures.

For the three months ended March 31, 2006 and 2005, the total stock-based compensation expense recognized in our net loss was $5,891,000 and $933,000, respectively. The impact of adopting SFAS No. 123R on our first quarter 2006 consolidated statement of operations was an increase in expenses of $4,543,000, with a corresponding increase in our loss from operations, loss before income taxes and minority interest, and net loss resulting from the first-time recognition of compensation expense associated with employee stock options. The impact on our basic and diluted net loss per common share was an increase in per share net loss of $0.08. For the three months ended March 31, 2006 and 2005, the total stock-based compensation cost capitalized as part of the cost of capital assets was $290,000 and $59,000, respectively.

The total unrecognized compensation cost at March 31, 2006 relating to non-vested share-based compensation arrangements granted under the 1997 Plan and 2003 Plan, before any capitalization, was $72,084,000. That cost is expected to be recognized over six years, with a weighted average period of 2.2 years.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

The adoption of SFAS No. 123R has no effect on net cash flow. Since we are not presently a taxpayer and have provided a valuation allowance against our deferred income tax assets net of liabilities, there is also no effect on our consolidated statement of cash flows. Had we been a taxpayer, we would have recognized cash flow resulting from tax deductions in excess of recognized compensation cost as a financing cash flow. We received total proceeds from the exercise of stock options of $1,164,000 and $1,125,000 in the three months ended March 31, 2006 and 2005, respectively.

The following table illustrates the pro forma net income and earnings per share that would have resulted in the three months ended March 31, 2005 from recognizing compensation expense associated with accounting for employee stock-based awards under the provisions of SFAS No. 123. The reported and pro forma net income and earnings per share for the three months ended March 31, 2006 are provided for comparative purposes only, as stock-based compensation expense is recognized in the financial statements under the provisions of SFAS No. 123R (in thousands, except per share data).


	Three Months Ended March 31,
	2006			2005
				(as adjusted)
Net loss as reported	$	(15,811	)	$	(9,434	)
Add: Stock-based employee compensation included in net loss (1)		5,600			874
Deduct:
Total stock-based employee compensation expense determined under fair value method for all awards, net of related income tax (1)(2)		(5,600	)		(2,219	)

Pro forma net loss	$	(15,811	)	$	(10,779	)

Net loss per share
Basic and diluted—as reported	$	(0.29	)	$	(0.18	)

Basic and diluted—pro forma	$	(0.29	)	$	(0.21	)

(1)	First quarter 2005 conformed to first quarter 2006 presentation.

(2)	Fair value of stock options computed using Black-Scholes-Merton option pricing model and the value of non-vested stock based on intrinsic value in accordance with SFAS No. 123R and SFAS No. 123.

Stock Options

During the first quarter of 2006, we issued options to purchase 474,720 shares of our common stock under the 2003 Plan. This included options to purchase 129,720 shares, granted to new employees as hiring incentives, having an exercise price equal to the stock price on the date of grant, graded vesting over four years, and a 10-year contractual life; an option to purchase 300,000 shares granted to our Chairman having an exercise price of $90.00, graded vesting over three years beginning in March 2010, and a 10-year contractual life; a fully vested option to purchase 25,000 shares granted to one of our directors having an exercise price equal to the stock price on the date of grant and a 10-year contractual life; and an option to purchase 20,000 shares having an exercise price equal to the stock price on the date of grant, graded vesting over two years, and a five-year contractual life granted to a consultant in exchange for services. These options are being accounted for in accordance with the guidance in SFAS No. 123R, with the exception of the consultant grant, which is being accounted for in accordance with the relevant accounting guidance for equity instruments granted to a non-employee.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

We estimate the fair value stock options under SFAS No. 123R at the date of grant using a Black-Scholes-Merton valuation model, which is consistent with the valuation technique we previously utilized to value options for the footnote disclosures required under SFAS No. 123. The following table provides the weighted average assumptions used in the Black-Scholes-Merton option valuation model to value options granted in the first quarter of 2006 and 2005. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant. The expected term (estimated period of time outstanding) of options granted in 2006 is based on the “simplified” method of estimating expected term for “plain vanilla” options allowed by SEC Staff Accounting Bulletin No. 107, and varies based on the vesting period and contractual term of the option. Prior to 2006, the expected term was based on our historical experience and estimate of future behavior of employees. Expected volatility for options granted in 2006 is based on an equally weighted average of the implied volatility of exchange traded options on our common stock expiring more than one year from the measurement date, and historical volatility of our common stock for a period equal to the option’s expected life. Prior to 2006, estimated volatility was based solely on the historical volatility of our common stock for a period equal to the option’s expected life. We have not declared dividends on our common stock.


	Three Months Ended March 31,
	2006		2005
Risk-free rate	4.3 – 4.8	%	3.6 – 4.4	%
Expected life (in years)	6.9		6.8
Expected volatility	55 – 69	%	85 – 101	%
Weighted average volatility	66	%	100	%
Expected dividends	0.0	%	0.0	%

The table below provides a summary of option activity under the combined plans as of March 31, 2006, and changes during the three months then ended:


	Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)					(in thousands)
Outstanding at January 1, 2006	5,125		$	28.66
Granted	475			71.43
Exercised	(189	)		7.03
Forfeited or Expired	—			—

Outstanding at March 31, 2006	5,411			33.17	7.3	$	67,635

Exercisable at March 31, 2006	714		$	11.28	3.3	$	20,917

The weighted average grant-date fair value of options granted during the three months ended March 31, 2006 and 2005 was $23.55 and $21.41, respectively. The total intrinsic value of options exercised during the three months ended March 31, 2006 and 2005 was $5,983,000 and $8,121,000, respectively.

Stock and Non-Vested Stock

We have granted stock and non-vested stock to employees and outside directors under the 2003 Plan. Prior to January 1, 2006, we accounted for grants of non-vested stock using the intrinsic value

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

method under the recognition and measurement principles of APB No. 25 and recognized the computed value of the non-vested stock in stockholders’ equity as an increase in additional paid-in-capital and a corresponding reduction in stockholders’ equity attributable to deferred compensation. The balance in deferred compensation was amortized ratably over the vesting period to non-cash compensation expense (before any capitalization) with a corresponding decrease in the deferred compensation balance.

Under SFAS No. 123R, grants of non-vested stock continue to be accounted for on an intrinsic value basis. No recognition of deferred compensation is made in stockholders’ equity, however. Instead, the amortization of the calculated value of non-vested stock grants is accounted for as a charge to non-cash compensation and an increase in additional paid-in-capital over the requisite service period. With the adoption of SFAS No. 123R, we offset the remaining unamortized deferred compensation balance ($9,684,000 at December 31, 2005) in stockholders’ equity against additional paid-in-capital. Amortization of the remaining unamortized balance will continue under SFAS No. 123R as described above.

In the first quarter of 2006 a total of 113,071 shares of non-vested stock were granted under the 2003 Plan. In January 2006, 78,671 shares having three-year graded vesting were issued to certain of our executive officers. In February and March 2006, a total of 34,400 shares of non-vested stock having four-year graded vesting were issued to new employees of Cheniere.

The table below provides a summary of the status of our non-vested shares under the 2003 Plan as of March 31, 2006, and changes during the three months then ended (in thousands except for per share information):


	Non-Vested Shares		Weighted Average Grant-Date Fair Value Per Share
Non-vested at January 1, 2006	550		$	21.06
Granted (1)	113			38.54
Vested	(218	)		7.50
Forfeited	—			—

Non-vested at March 31, 2006	445		$	32.14

(1)	Includes an award of 25,000 non-vested shares granted under the French Addendum to the 2003 Plan, which have not been issued and are not outstanding at March 31, 2006.

The weighted average grant-date fair value of non-vested stock granted during the three months ended March 31, 2006 and 2005 was $4,358,000 and $-0-, respectively. The total grant-date fair value of shares vested during the three months ended March 31, 2006 and 2005 was $1,635,000 and $1,716,000, respectively.

Share-Based Plan Descriptions and Information

Our 1997 Plan provides for the issuance of stock options to purchase up to 5,000,000 shares of our common stock, all of which has been granted. Non-qualified stock options were granted to employees, contract service providers and outside directors. Option terms for the remaining unexercised options are five years with vesting that generally occurs on a graded basis over three years.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Awards providing for the issuance of up to an aggregate of 8,000,000 shares of our common stock may be made under our 2003 Plan. These awards may be in the form of non-qualified stock options, incentive stock options, purchased stock, restricted (non-vested) stock, bonus (unrestricted) stock, stock appreciation rights, phantom stock, and other stock-based performance awards deemed by the Compensation Committee to be consistent with the purposes of the 2003 Plan. To date, the only awards made by the Compensation Committee have been in the form of non-qualified stock options, restricted stock and bonus stock. Beginning in 2005, stock options granted to employees as hiring incentives have been granted at the money with 10-year terms and graded vesting over four years. Prior to that time, stock options granted as hiring incentives were granted at the money with five-year terms and graded vesting over three years. Retention grants made to employees provide for exercise prices at or in excess of the stock price on the grant date, 10-year terms, and graded vesting over three years, which commences on the fourth anniversary of the grant date. Restricted stock that has been granted as a hiring incentive vests over four years on a graded basis, while restricted stock granted from a bonus pool vests over three years. Shares issued under the 2003 Plan are generally newly issued shares.

NOTE 19—Subsequent Events

On April 4, 2006, Cheniere LNG Marketing, Inc. (“Cheniere Marketing”), our wholly-owned subsidiary, entered into a 10-year Gas Purchase and Sale Agreement with PPM Energy, Inc. (“PPM”), a subsidiary of Scottish Power PLC. Upon completion of certain of our facilities, the agreement gives Cheniere Marketing the ability to sell to PPM up to 600,000 MMBtus of natural gas per day at a Henry Hub-related market index price, and calls for Cheniere Marketing to allocate to PPM a portion of the LNG that it procures under certain long-term LNG supply agreements.

On April 13, 2006, Corpus Christi LNG, L.P. (“Corpus Christi LNG”) entered into an EPC agreement with La Quinta LNG Partners, LP (“La Quinta”). La Quinta is a limited partnership whose general partners are Zachry Construction Corporation and AMEC E&C Services, Inc. Under the terms of the EPC agreement, La Quinta will provide Corpus Christi LNG with certain preliminary design, engineering, procurement, pipeline dismantlement, removal and construction, road construction and site preparation work on a reimbursable basis in connection with the construction of the Corpus Christi LNG facility. Payments anticipated to be made by Corpus Christi LNG to La Quinta for work performed under the EPC Agreement are not expected to exceed $50,000,000.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

We are engaged primarily in the business of developing and constructing, and then owning and operating, a network of three onshore LNG receiving terminals, and related natural gas pipelines, along the Gulf Coast of the United States. We are also engaged, to a limited extent, in oil and natural gas exploration and development activities in the Gulf of Mexico. We operate four business activities: LNG receiving terminal development, natural gas pipeline development, LNG and natural gas marketing and oil and gas exploration and development. At this stage in our development, our operations are divided into two reporting segments in our financial statements: LNG Receiving Terminal Development and Oil and Gas Exploration and Development.

LNG Receiving Terminal Development Business

We have focused our development efforts on three, 100% owned LNG receiving terminal projects at the following locations: Sabine Pass LNG in western Cameron Parish, Louisiana on the Sabine Pass Channel; Corpus Christi LNG near Corpus Christi, Texas; and Creole Trail LNG at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. In addition, we own a 30% interest in a fourth project, Freeport LNG, located on Quintana Island near Freeport, Texas. Our three terminals have an aggregate designed regasification capacity of approximately 10.0 Bcf/d, subject to expansion. We have entered into long-term TUAs with Total and Chevron USA for an aggregate of 2.0 Bcf/d of the available regasification capacity, and we have reserved 2.5 Bcf/d for use by Cheniere Marketing.

Construction of Phase 1 of our Sabine Pass LNG receiving terminal commenced in March 2005, and we anticipate commencing operations at the terminal in 2008. Preliminary work including certain design and engineering work associated with construction of the Corpus Christi LNG receiving terminal commenced during the first quarter of 2006, and we anticipate commencing operations at the facility in 2010. Construction of the Creole Trail LNG receiving terminal is anticipated to commence in 2007, and we anticipate commencing operations at the facility in 2011.

Natural Gas Pipeline Development Business

We anticipate developing natural gas pipelines from each of our three LNG receiving terminals to provide optimal access to North American natural gas markets. Development efforts to date have focused primarily on advancing our pipeline projects through the regulatory review and authorization process. Recently, our development efforts have also included the construction and operation of our proposed natural gas pipelines. Certain preliminary work including engineering, survey and easement acquisition related to our Sabine Pass pipeline are in progress. Subject to FERC approval of the implementation plan for construction of our Sabine Pass pipeline, we anticipate beginning construction in early 2007. We anticipate commencing operations of the pipeline in the fourth quarter of 2007.

LNG and Natural Gas Marketing Business

Our LNG and natural gas marketing business is in its early stages of development. We plan to utilize a portion of our planned LNG receiving terminal regasification capacity through Cheniere Marketing (1.5 Bcf/d and 1.0 Bcf/d currently reserved at the Sabine Pass LNG and Corpus Christi LNG receiving terminals, respectively). Through utilization of this capacity, we intend to purchase LNG from foreign suppliers, arrange transportation of LNG to our network of LNG receiving terminals, arrange the transportation of revaporized natural gas through our pipelines and other interconnected pipelines and sell natural gas to buyers in the North American market. In addition, we also expect to enter into domestic natural gas purchase and sale transactions as part of our marketing activities.

Oil and Gas Exploration and Development Business

Although our focus is primarily on the development of LNG-related businesses, we continue to be involved to a limited extent in oil and gas exploration, development and exploitation, and in exploitation of our existing 3D seismic database through prospect generation. We have historically focused on evaluating and generating drilling prospects using a regional and integrated approach with a large seismic database as a platform. From time to time, we will invest in drilling a share of these prospects and may pursue opportunities in other geographic locations as well.

Our current oil and gas exploration and development activities are focused on two areas:

•

the Cameron Project, which covers an area of approximately 230 square miles extending roughly three to five miles on either side of the westernmost 28 miles of Louisiana coastline; and

•

the Offshore Texas Project Area, which covers approximately 6,800 square miles in the shallow waters offshore Texas and the West Cameron Area of offshore Louisiana.

Liquidity and Capital Resources

We are primarily engaged in LNG-related business activities. Our three LNG terminal projects, as well as our proposed pipelines, will require significant amounts of capital and are subject to risks and delays in completion. In addition, our marketing business will need a substantial amount of capital for hiring employees, satisfying creditworthiness requirements of contracts and developing the systems necessary to implement our business strategy. Even if successfully completed and implemented, our LNG-related business activities are not expected to begin to operate and generate significant cash flows before 2008. As a result, our business success will depend to a significant extent upon our ability to obtain the funding necessary to construct our three LNG terminals and related pipelines, 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 the cost of completing our three LNG receiving terminals will be approximately $3 billion, before financing costs. In addition, we expect that capital expenditures of approximately $800 million to $1 billion will be required to construct our three proposed pipelines.

As of March 31, 2006, we had working capital of $807.1 million. While we believe that we have adequate financial resources available to us through 2006, we must augment our existing sources of cash with significant additional funds in order to carry out our long-term business plan. We currently expect that our capital requirements will be financed in part through cash on hand, 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 LNG Receiving Terminals

Sabine Pass LNG

We currently estimate that the cost of constructing Phase 1 of the Sabine Pass LNG facility will be approximately $900 million to $950 million, before financing costs, which will be funded as described below. Phase 2 of the Sabine Pass LNG facility may be constructed in stages. The first stage is estimated to cost approximately $500 million to $550 million, before financing costs. We are currently evaluating funding alternatives for the first stage of construction of Phase 2 of the Sabine Pass LNG facility, which may include existing cash balances, proceeds from debt or equity offerings, or a combination thereof. The cost estimate for the second stage of constructing Phase 2 of the Sabine Pass LNG facility is still under evaluation.

Sabine Pass Credit Facility

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 Phase 1 of 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 could make an initial borrowing under the Sabine Pass Credit Facility, it was required to provide evidence that it had received equity contributions in amounts sufficient to fund $233.7 million of the project costs. As of December 31, 2005, the $233.7 million equity contributions had been funded and, as a result, we began drawing under the Sabine Pass Credit Facility in January 2006. As of March 31, 2006, $70 million had been drawn under the Sabine Pass Credit Facility. In addition, we made an intercompany subordinated loan in the amount of $37.4 million to Sabine Pass LNG in late 2005 to fund certain costs related to Phase 1 of the project.

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 Sabine Pass Credit Facility. Administrative fees must also be paid annually to the agent and the collateral agent. 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 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.

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 $371,000 held in these accounts as of March 31, 2006 is classified as restricted on our balance sheet.

The Sabine Pass Credit Facility contains customary conditions precedent to borrowings, as well as customary affirmative and negative covenants. Sabine Pass LNG has obtained, and may in the future seek, consents, waivers and amendments to the Sabine Pass Credit Facility documents. The obligations of Sabine Pass LNG under the Sabine Pass Credit Facility are secured by all of Sabine Pass LNG’s personal property, including the Total and Chevron USA TUAs and the partnership interests in Sabine Pass LNG.

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

EPC Agreement

Sabine Pass LNG issued an NTP in early April 2005, which required Bechtel to commence all other aspects of the work under the EPC agreement. Sabine Pass LNG agreed to pay to Bechtel a contract price of $646.9 million plus certain reimbursable costs for the work under the EPC agreement. This contract price is subject to adjustment for changes in certain commodity prices, contingencies, change orders and other items. Payments under the EPC agreement will be made in accordance with the payment schedule set forth in the EPC agreement. The contract price and payment schedule, including milestones, may be amended only by change order. Bechtel will be liable to Sabine Pass LNG for certain delays in achieving substantial completion, minimum acceptance criteria and performance guarantees. Bechtel will be entitled to a scheduled bonus of $12 million, or a lesser amount in certain cases, if on or before April 3, 2008, Bechtel 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 $67,000 per day (up to a maximum of $6 million) for each day that commercial operation is achieved prior to April 1, 2008. As of May 2006, change orders for $65.8 million were approved, thereby increasing the total contract price to $712.7 million. We anticipate additional change orders intended to mitigate ongoing effects of the 2005 hurricanes that would increase the contract price by an amount not expected to exceed $50 million. We have submitted a related change order to our lenders for approval under the Sabine Pass Credit Facility. In addition, we have submitted a request to the lenders that, if approved, would allow us to make subordinated loans related to such change orders for up to an additional $50 million to Sabine Pass LNG.

Bechtel has claimed events of force majeure arising out of three hurricanes in 2005 along the U.S. Gulf Coast. Sabine Pass LNG is currently in negotiations with Bechtel and certain subcontractors concerning additional activities and expenditures in order, among other things, to attract sufficient skilled labor to mitigate potential schedule delays and provide a reasonable opportunity for Bechtel to attain the initial target bonus date of April 3, 2008. As part of these negotiations, we have agreed in principle to defer the date by which substantial completion of the entire project is required to be accomplished under the EPC contract from September 3 to December 20, 2008. In the absence of substantial completion by such date, Bechtel would be obligated to pay us certain liquidated damages as provided under the terms of the contract. We expect that cost under the above-described arrangement will not exceed $50 million, although such amount is subject to change, requires approval of the lenders under our Sabine Pass Credit Facility and requires that a change order be agreed upon with Bechtel.

Customer TUAs

Total has paid Sabine Pass LNG nonrefundable advance capacity reservation fees of $20 million in the aggregate in connection with the reservation under a 20-year TUA of approximately 1.0 Bcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal. These capacity reservation fee payments will be amortized over a 10-year period as a reduction of Total’s regasification capacity fee under the TUA.

Chevron USA has paid Sabine Pass LNG nonrefundable advance capacity reservation fees of $20 million in the aggregate in connection with the reservation under a 20-year TUA of approximately 1.0 Bcf/d of LNG regasification capacity at the Sabine Pass LNG receiving terminal. These capacity reservation fee payments will be amortized over a 10-year period as a reduction of Chevron USA’s regasification capacity tariff under the TUA.

Cheniere Marketing has entered into a TUA with Sabine Pass LNG for 1.5 Bcf/d of regasification capacity at our Sabine Pass LNG receiving terminal, which capacity will be reduced to 600 MMcf/d in the event that both the Total TUA and the Chevron TUA commence prior to completion of Phase 2 of our Sabine Pass LNG facility.

Proposed Capacity Offering

In April 2006, Sabine Pass LNG began a formal request-for-proposal process with unaffiliated third parties for up to 500 MMcf/d of regasification capacity at the Sabine Pass LNG receiving terminal. We expect the request-for-proposal period to conclude by the end of the second quarter of 2006; however, we may not be able to obtain any TUAs on terms acceptable to us, or at all.

Corpus Christi LNG

We currently estimate that the cost of constructing the Corpus Christi LNG facility will be approximately $650 million to $750 million, before financing costs. This estimate is based in part on our negotiations with a major international EPC contractor. Our cost estimate is subject to change due to such items as cost overruns, change orders, changes in commodity prices (particularly steel) and escalating labor costs. We expect to commence operations at the Corpus Christi LNG receiving terminal in early 2010.

Development

On April 13, 2006, Corpus Christi LNG entered into an EPC agreement with La Quinta LNG Partners, LP (“La Quinta”). La Quinta is a limited partnership whose general partners are Zachry Construction Corporation and AMEC E&C Services, Inc. Under the terms of the EPC agreement, La Quinta will provide Corpus Christi LNG with certain preliminary design, engineering, procurement, pipeline dismantlement, removal and construction, road construction and site preparation work on a reimbursable basis in connection with the construction of the Corpus Christi LNG facility. Payments anticipated to be made by Corpus Christi LNG to La Quinta for work performed under the EPC agreement are not expected to exceed $50 million. We expect to commence operations at the Corpus Christi LNG receiving terminal in early 2010.

Funding

We currently expect to fund the amounts payable under the La Quinta EPC agreement from existing cash balances. The remainder of the project cost is expected to be funded through project financing similar to that used for our Sabine Pass LNG facility, existing cash, proceeds from debt or equity offerings, or a combination thereof.

Customers

Cheniere Marketing has entered into a TUA with Corpus Christi LNG for 1.0 Bcf/d of regasification capacity at the LNG receiving terminal.

Creole Trail LNG

We currently estimate that the cost of constructing the Creole Trail LNG facility will be approximately $850 million to $950 million, before financing costs. Our cost estimate is preliminary and subject to change. We currently expect to fund the costs of the Creole Trail LNG terminal project using financing similar to that used for our Sabine Pass LNG facility, proceeds from future debt or equity offerings, existing cash 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.

Other LNG Interests

We have a 30% limited partner interest in Freeport LNG. Under the limited partnership agreement of Freeport LNG, development expenses of the Freeport LNG project and other Freeport LNG cash needs generally are to be funded out of Freeport LNG’s own cash flows, borrowings or other sources, and, up to a pre-agreed total amount, with capital contributions by the limited partners. In July 2004, Freeport LNG entered into a credit agreement with ConocoPhillips to provide a substantial majority of the debt financing. We received capital calls, and made capital contributions, in the amount of approximately $2.1 million in 2005. In December 2005, Freeport LNG announced that it had closed a $383 million private placement of notes, which will be used to fund the remaining portion of the initial phase of the project, a portion of the cost of expanding the LNG receiving terminal and the development of 7.5 Bcf of underground salt cavern gas storage. As a result of such financing being obtained, we do not anticipate that any capital calls will be made upon the limited partners of Freeport LNG in the foreseeable future.

Although no capital calls are currently outstanding, and we do not anticipate any in the foreseeable future, 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.

Our Proposed Pipelines

We estimate that approximately $800 million to $1 billion of total capital expenditures will be required to construct our three proposed pipelines. We currently expect to fund the costs of our three proposed pipelines from our existing cash balances, project financing, proceeds from future debt or equity offerings, or a combination thereof.

In February 2006, Cheniere Sabine Pass Pipeline Company (“Sabine Pass Pipeline Company”), our wholly-owned subsidiary, entered into an EPC pipeline contract with Willbros. Under the EPC pipeline contract, Willbros will provide Sabine Pass Pipeline Company with services for the management, engineering, material procurement, construction and construction management of the Sabine Pass pipeline. Sabine Pass Pipeline Company entered into the EPC pipeline contract sufficiently in advance of commencement of physical construction of the pipeline in order to perform detailed engineering and procure materials. This EPC pipeline contract, among other things, provides for a guaranteed maximum price of approximately $67.7 million, subject to adjustment under certain circumstances, as provided in the contract. We estimate that the total cost to construct the pipeline, including certain work not included in the EPC pipeline contract, such as interconnection with third-party pipelines, will be approximately $90 million. Our total cost estimate is preliminary and subject to change due to such items as cost overruns, change orders, changes in commodity prices (particularly steel) and escalation of labor costs. Construction contracts for the Corpus Christi and Creole Trail pipelines have not been negotiated.

Our Marketing Business

We are in the early stages of developing our LNG and natural gas marketing business. We will need to spend funds to develop our marketing business, including capital required to satisfy any creditworthiness requirements under contracts. These costs are expected to be incurred to develop the systems necessary to implement our business strategy and to hire additional employees to conduct our natural gas marketing activities. We expect to fund these expenses with available cash balances.

In April 2006, Cheniere Marketing entered into a 10-year Gas Purchase and Sale Agreement with PPM. Upon completion of certain of our facilities, the agreement gives Cheniere Marketing the ability to sell to PPM up to 600,000 MMBtus of natural gas per day at a Henry Hub-related market index price, and calls for Cheniere Marketing to allocate to PPM a portion of the LNG that it procures under certain long-term LNG supply agreements.

Other Capital Resources

Convertible Senior Unsecured Notes

In July 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 pursuant to the terms of the indenture governing the Notes 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 indenture governing the Notes contains customary reporting requirements.

Concurrent with the issuance of the 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. As of March 31, 2006, no holders had elected to convert their Notes.

We currently intend to use the net proceeds from the Notes offering primarily for the following purposes: (i) to fund Phase 2 of the Sabine Pass LNG receiving terminal, development and construction of the Corpus Christi and/or Creole Trail LNG receiving terminals and pipelines, (ii) to pay debt service obligations and/or (iii) for general corporate purposes.

Term Loan

In August 2005, Cheniere LNG Holdings entered into a $600 million Term Loan with Credit Suisse. The Term Loan has an interest rate equal to 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 6—”Derivative Instruments” to our Consolidated Financial Statements). On December 30, 2005, Cheniere LNG Holdings made the first required quarterly principal payment of $1.5 million. 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. These funds are restricted and to be disbursed only for 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 these accounts are controlled by Credit Suisse, the collateral agent, our cash and cash equivalent undisbursed balance of $159.6 million held in these accounts as of March 31, 2006 is classified as restricted on our consolidated balance sheet. Of this amount, $15 million is classified as non-current due to the timing of certain required debt amortization payments.

We currently intend to use the remaining proceeds from the Term Loan primarily for the following purposes: (i) to fund requirements in excess of amounts available under the Sabine Pass Credit Facility for the construction of the Sabine Pass LNG receiving terminal, (ii) to pay specified Term Loan debt service obligations and certain other expenses, (iii) to fund Phase 2 of the Sabine Pass LNG receiving terminal, (iv) to fund the development and construction of the Corpus Christi and/or Creole Trail LNG receiving terminals and pipelines and/or (v) for general corporate purposes.

Short-Term Liquidity Needs

We anticipate funding our more immediate liquidity requirements, including some expenditures related to the construction of our LNG receiving terminals, the development of our pipeline business, the growth of our marketing business and our oil and gas exploration, development and exploitation activities, through a combination of any or all of the following:

•

cash balances;

•

drawings under the Sabine Pass Credit Facility;

•

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

•

LNG receiving terminal capacity reservation fees;

•

collection of receivables; and

•

sales of prospects generated by our oil and gas exploration and development business.

Historical Cash Flows

Net cash used in operations increased to $20.5 million during the three months ended March 31, 2006 compared to $2.9 million in the same period of 2005. This $17.6 million increase was primarily due to continued development of our LNG receiving terminals and related pipelines and increased costs to support such activities.

Net cash used in investing activities was $59.8 million during the three months ended March 31, 2006 compared to net cash used in investing activities of $43.7 million during the three months ended March 31, 2005. During the first three months of 2006, we invested $73.3 million relating to Phase 1 construction activities at our Sabine Pass LNG facility. We also invested $1.7 million and $2.0 million in fixed assets and oil and gas drilling activities, respectively. These investment activities were partially offset by a $17.2 million use of our restricted cash investments during the first quarter of 2006 related to funding of our Sabine Pass LNG construction activities discussed above and to make payments of interest and principal relating to our Term Loan. During the first three months of 2005, we made an advance of $32.3 million to Bechtel related to the construction of our Sabine Pass LNG receiving terminal. We also invested $6.5 million in construction-in-progress costs related to the facility. The

remaining first quarter 2005 cash used in investing activities primarily related to transfers to the Sabine Pass LNG restricted cash collateral accounts under the Sabine Pass Credit Facility, purchase of fixed assets, advances to Freeport LNG and oil and gas property additions.

Net cash provided by financing activities during the first three months of 2006 was $65.8 million compared to $15.0 million used in financing activities in the same period of 2005. During the first three months of 2006, we received proceeds from borrowings under the Sabine Pass Credit Facility totaling $70.0 million and $1.2 million received from the issuance of common stock related to stock option exercises. These proceeds were partially offset by a $1.5 million Term Loan principal payment and $3.0 million in debt issuance costs related to the Sabine Pass Credit Facility which became due at first borrowing under the facility. In addition, we paid federal withholding taxes of $932,000 in exchange for 24,300 shares of our common stock, which vested in February 2006 and related to stock previously awarded to an executive officer. During the first three months of 2005, we incurred $16.6 million in debt issuance costs primarily related to the Sabine Pass Credit Facility, partially offset by $1.6 million in proceeds from the exercise of stock options and warrants.

Due to the factors described above, our cash and cash equivalents decreased to $678.1 million as of March 31, 2006 compared to $692.6 million at December 31, 2005, and our working capital decreased to $807.1 million as of March 31, 2006 compared to $810.1 million at December 31, 2005.

Issuances of Common Stock

During the first three months of 2006, a total of 168,601 shares of our common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of $1.2 million. In addition, 15,858 shares of common stock were issued in satisfaction of a cashless exercise of options to purchase 20,000 shares of common stock.

In January 2006, 78,671 shares were issued to executive officers in the form of non-vested (restricted) stock awards related to our performance in 2005. During the first three months of 2006, we issued 9,400 shares of non-vested restricted stock to certain employees.

As discussed above, we paid federal payroll withholding taxes of $932,000 in exchange for 24,300 shares of our common stock which vested in February 2006 related to stock previously awarded to an executive officer. These shares are now held as treasury shares, at cost, and may be reissued in satisfaction of future stock option exercises.

Off-Balance Sheet Arrangements

As of March 31, 2006, we had no off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed the debt of any other party.

Results of Operations—Comparison of the Three-Month Periods Ended March 31, 2006 and 2005 (As Adjusted)

Overview

Our financial results for the three months ended March 31, 2006 reflect a net loss of $15.8 million, or $0.29 per share (basic and diluted), compared to a net loss of $9.4 million, or $0.18 per share (basic and diluted), for the three months ended March 31, 2005.

The major factors contributing to our net loss of $15.8 million during the first quarter of 2006 were LNG terminal and pipeline development expenses of $8.3 million, general and administrative expenses of $13.2 million and interest expense of $11.1 million. These factors were partially offset by interest income of $9.5 million and a $7.4 million tax benefit that was recorded in accordance with SFAS No. 109. The major factors contributing to our $9.4 million net loss during the first three months of 2005 were LNG receiving terminal development expenses of $5.4 million and general and administrative expenses of $5.0 million.

LNG Receiving Terminal Development and Related Pipeline Activities

LNG receiving terminal development expenses were 54% higher in the first three months of 2006 ($8.3 million) than in the first quarter of 2005 ($5.4 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, terminal site rental costs, 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 Phase 1 of our Sabine Pass LNG receiving terminal have been capitalized.

In the first quarter of 2006, we recorded $4.2 million of LNG terminal development expenses attributable to Phase 2 of the Sabine Pass LNG project, Creole Trail LNG and Corpus Christi LNG receiving terminals. In addition, we incurred $1.2 million of development expenses primarily related to pipeline development activities for our Creole Trail LNG project. We also incurred $2.9 million in other LNG receiving terminal development expenses, including $2.1 million in LNG employee-related costs. Our LNG staff increased from an average of 19 employees in the first quarter of 2005 to an average of 36 employees in the first quarter of 2006 as a result of the expansion of our business. LNG employee-related costs for the first quarter of 2006 included non-cash compensation of $1.2 million.

In the first quarter of 2005, we recorded $1.2 million in LNG receiving terminal development expenses related to the Creole Trail LNG receiving terminal. In addition, we incurred $2.2 million of development expenses primarily related to our Creole Trail pipeline development activities. We incurred $654,000 in LNG receiving terminal development expenses in the first quarter of 2005 with respect to the Corpus Christi LNG receiving terminal and related pipeline. This amount was partially offset by $97,000 reimbursed by the 33.3% limited partner minority interest for the period prior to our February 2005 acquisition of such minority interest. In addition, we incurred $1.7 million in other LNG receiving terminal development expenses, including $1.0 million in LNG employee-related costs. LNG employee-related costs for the first quarter of 2005 also included non-cash compensation of $292,000 related to the amortization of deferred compensation associated with non-vested stock awarded in 2004.

In the first quarter of 2005, we recorded our 30% equity share of the net loss of Freeport LNG of $844,000. As of March 31, 2006, our basis of the investment in Freeport LNG was zero, and as a result, we did not record $3.2 million of our equity share of the loss of the partnership because we did not guarantee any obligations of Freeport LNG and had not committed to provide additional financial support to Freeport LNG at that time (see Note 5—”Investment in Limited Partnership” to our Consolidated Financial Statements).

General and Administrative Expenses

General and administrative (“G&A”) expenses primarily relate to our general corporate, marketing and other activities. These expenses increased $8.2 million, or 164%, to $13.2 million in the first three months of 2006 compared to $5.0 million in the first three months of 2005. The increase in G&A resulted primarily from the expansion of our business (including increases in corporate and marketing staff from an average of 28 employees in the first three months of 2005 to an average of 84 employees in the first three months of 2006). Corporate and marketing employee-related costs for the first three months of 2006 included non-cash compensation of $4.2 million. G&A expenses related to the development of our LNG and natural gas marketing business totaled $1.1 million for the first three months of 2006.

Exploration Expense

Exploration expense includes oil and gas exploration activities that are required to be expensed under the successful efforts method of accounting. In the first three months of 2006, exploration expense increased to $838,000 compared to $542,000 in the first three months of 2005. The increase was due to higher lease abandonment costs and the expensing of drilling costs associated with an unsuccessful exploration well.

Depreciation, Depletion and Amortization Expenses

Depreciation, depletion and amortization (“DD&A”) expenses increased $401,000, or 196%, to $606,000 million in the first three months of 2006 from $205,000 in the first three months of 2005. The increase in DD&A expenses was primarily due to a $401,000 increase in the first three months of 2006 associated with the acquisition of furniture, fixtures and equipment and office space leasehold improvements associated with the expansion of our business.

Derivative Gain, Net

During the first three months of 2006, we recorded a net derivative gain of $761,000 attributable to the ineffective portion of our interest rate swaps.

Interest Income

Interest income increased to $9.5 million in the first three months of 2006 from $1.8 million in the first three months of 2005 because of a higher average cash and cash equivalents balance due to the issuance of the Notes, higher interest rates and completion of the Term Loan during the third quarter of 2005.

Interest Expense

Interest expense, net of capitalization, and impact of interest rate swaps was $11.1 million in the first three months of 2006 compared to zero in the first three months of 2005. This increase was primarily attributable to the issuance of the Notes and completion of the Term Loan during the third quarter of 2005. Total capitalized interest was $3.4 million in the first quarter of 2006, primarily related to interest and other related costs attributable to the Sabine Pass Credit Facility.

Oil and Gas Activities

Oil and gas revenues decreased by $315,000, or 43%, to $422,000 in the first three months of 2006 from $737,000 in the first three months of 2005 as a result of a 55% decrease in production volumes (to 61,000 Mcfe in the first three months of 2006 compared to 135,000 Mcfe in the first three months of 2005), partially offset by a 27% increase in average natural gas prices to $6.83 per thousand cubic feet (“Mcf”) in the first three months of 2006 from $5.39 per Mcf in the first three months of 2005. 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 during the first three months of 2005; however, the production from this well was minimal during the first three months of 2006 as the reserves were fully depleted.

Other Income

In the first three months of 2006, we recorded a $176,000 gain associated with the sale of an oil and gas exploration project.

Income Tax Benefit

A tax benefit of $7.4 million was recognized in the first quarter of 2006 relating to the portion of the change in our tax asset valuation account that is allocable to the deferred income tax on items reported in accumulated other comprehensive income on derivative instruments in accordance with SFAS No. 109, Accounting for Income Taxes, and EITF Abstracts, Topic D-32.

Other Matters

Critical Accounting Estimates and Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives but involve an implementation and interpretation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to 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.

Accounting for LNG Activities

Generally, we begin capitalizing the costs of our LNG receiving terminals and related pipelines once the individual project meets the following criteria: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals, and other preliminary investigation and development activities related to our LNG receiving terminals and related natural gas pipelines.

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land costs, costs of lease options and the cost of certain permits which are capitalized as intangible LNG assets. The costs of lease options are amortized over the life of the lease once it is obtained. If no lease is obtained, the costs are expensed. Site rental costs and related amortization of capitalized options have been capitalized during the construction period through the end of 2005. Beginning in 2006, such costs will be expensed as required by FSP 13-1.

During the construction periods of our LNG receiving terminals and related pipelines, 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 operations, capitalized interest, as a component of the total cost, will be amortized over the estimated useful life of the asset.

In the first quarter of 2005, we began capitalizing direct costs associated with the construction of Phase I of our Sabine Pass LNG facility. In January and March 2006, we began capitalizing direct costs associated with the construction of the Sabine Pass Pipeline and the Corpus Christi LNG facility, respectively.

Revenue Recognition

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

Change in Method of Accounting for Investments in Oil and Gas Properties

Effective January 1, 2006, we converted from the full cost method to the successful efforts method of accounting for our investments in oil and gas properties. While our primary focus is the development of our LNG-related businesses, we have continued to be involved, to a limited extent, in oil and gas exploration and development activities in the U.S. Gulf of Mexico. We believe, in light of our current level of exploration and development activities, the successful efforts method of accounting provides a better matching of expenses to the period in which oil and gas production is realized. As a result, we believe that the change in accounting method at this time is appropriate. The change in accounting method constitutes a “Change in Accounting Principle,” requiring that all prior period financial statements be adjusted to reflect the results and balances that would have been reported had we been following the successful efforts method of accounting from our inception. The cumulative effect of the change in accounting method as of December 31, 2004 and 2005 was to reduce the balance of our net investment in oil and gas properties and retained earnings at those dates by $18.2 million and $18.0 million, respectively. The change in accounting method resulted in an increase in the net loss of $219,000, or $0.00 per share (basic and diluted), for the three months ended March 31, 2005 (see Note 17—”Adjustment to Financial Statements – Successful Efforts” to our Consolidated Financial Statements). The change in method of accounting has no impact on cash or working capital.

Cash Flow Hedges

As defined in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, 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

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.

Share-Based Compensation Expense

Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123R using the modified prospective transition method, and therefore have not restated prior periods’ results. Under this method, we recognize compensation expense for all share-based payments granted after January 1, 2006 and prior to, but not yet vested as of, January 1, 2006, in accordance with SFAS 123R using the Black-Scholes-Merton option valuation model. Under the fair value recognition provisions of SFAS 123R, we recognize stock-based compensation net of an estimated forfeiture rate and only recognize compensation cost for those shares expected to vest on a straight-line basis over the requisite service period of the award. Prior to the adoption of SFAS 123R, we accounted for share-based payments under APB No. 25 and accordingly, did not recognize compensation expense for options granted that had an exercise price greater than or equal to the market value of the underlying common stock on the date of grant.

Determining the appropriate fair value model and calculating the fair value of share-based payment awards require the input of highly subjective assumptions, including the expected life of the share-based payment awards and stock price volatility. We believe that implied volatility, calculated based on traded options of our common stock, combined with historical volatility is an appropriate indicator of expected volatility and future stock price trends. Therefore, expected volatility for the quarter ended March 31, 2006 was based on a combination of implied and historical volatilities. The assumptions used in calculating the fair value of share-based payment awards represent our best estimates, but these estimates involve inherent uncertainties and the application of management judgment. As a result, if factors change and we use different assumptions, our stock-based compensation expense could be materially different in the future. In addition, we are required to estimate the expected forfeiture rate and only recognize expense for those shares expected to vest. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation expense could be significantly different from what we have recorded in the current period. See Note 18—”Share-Based Compensation” to our Consolidated Financial Statements for a further discussion on share-based compensation.

New Accounting Pronouncements

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. SFAS No. 155 provides entities with relief from having to separately determine the fair value of an embedded derivative that would otherwise be required to be bifurcated for its host contract in accordance with SFAS No. 133. SFAS No. 155 allows an entity to make an irrevocable election to measure such a hybrid financial instrument at fair value in its entirety, with changes in fair value recognized in earnings. SFAS No. 155 is effective for all financial instruments acquired, issued or subject to a remeasurement event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We believe that the adoption of SFAS No. 155 will not have a material impact on our financial position, results of operations or cash flows.

In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of Financial Assets an Amendment to FASB Statement No. 140. Once effective, SFAS No. 156 will require entities to recognize

a servicing asset or liability each time they undertake an obligation to service a financial asset by entering into a servicing contract in certain situations. This statement also requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value and permits a choice of either the amortization or fair value measurement method for subsequent measurement. The effective date of this statement is for annual periods beginning after September 15, 2006, with earlier adoption permitted as of the beginning of an entity’s fiscal year provided the entity has not issued any financial statements for that year. We do not plan to adopt SFAS No. 156 early, and we are currently assessing the impact on our consolidated financial statements.

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 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.

Interest Rates

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.

At March 31, 2006, we had $992 million of debt outstanding. Of this amount, our $325 million of Notes bore a fixed interest rate of 2.25%. The Term Loan and Sabine Pass Credit Facility, totaling $597 million and $70 million, respectively, bear interest at floating rates; however, we entered into interest rate swaps with respect to these loan amounts (see Note 6—”Derivative Instruments” to our Consolidated Financial Statements).

The following table summarizes the fair market values of our existing interest rate swap agreements as of March 31, 2006 (in thousands):

Variable to Fixed Swaps


Maturity Date	Weighted Average Notional Principal Amount		Fixed Interest Rate (Pay)	Weighted Average Interest Rate		Fair Market Value (1)
March through December 2006	$	973,517	3.75% - 4.49%	US $	LIBOR BBA	$	6,208
January through December 2007		1,135,432	3.75% - 4.49%	US $	LIBOR BBA		11,436
January through December 2008		1,276,168	3.98% - 5.98%	US $	LIBOR BBA		7,855
January through December 2009		1,275,948	4.49% - 5.98%	US $	LIBOR BBA		(1,810	)
January through December 2010		1,017,093	4.98% - 5.98%	US $	LIBOR BBA		(236	)
January through December 2011		662,442	4.98%	US $	LIBOR BBA		1,840
January through December 2012		650,100	4.98%	US $	LIBOR BBA		1,063

						$	26,356

(1)	The fair market value is based upon a marked-to-market calculation utilizing an extrapolation of third-party mid-market LIBOR rate quotes at March 31, 2006.

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 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

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, as of March 31, 2006, 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.

ITEM 6. EXHIBITS

(a) Each of the following exhibits is filed herewith:


10.1		Agreement for Engineering, Procurement and Construction Services, effective February 1, 2006, between Cheniere Sabine Pass Pipeline Company and Willbros Engineers, Inc.

10.2		Gas Purchase and Sale Agreement, dated April 4, 2006, between Cheniere LNG Marketing, Inc. and PPM Energy, Inc.

10.3		Engineering, Procurement and Construction Services Agreement for Preliminary Work, dated April 13, 2006, between Corpus Christi LNG, LLC and La Quinta LNG Partners, LP

10.4		Change Orders 28, 29 and 31 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004 between Sabine Pass LNG, L.P. and Bechtel Corporation

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

SIGNATURES

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

CHENIERE ENERGY, INC.

/s/ Craig K. Townsend

Vice President and Chief Accounting Officer
(on behalf of the registrant and as principal accounting officer)

Date: May 5, 2006