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, 2007

¨	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.)

700 Milam Street, Suite 800

Houston, Texas

(Address of principal executive offices)

77002

(Zip Code)

(713) 375-5000

(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 April 30, 2007, there were 56,266,353 shares of Cheniere Energy, Inc. Common Stock, $0.003 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 Sheets	1
	Consolidated Statements of Operations	2
	Consolidated Statement of Stockholders’ Equity	3
	Consolidated Statements of Cash Flows	4
	Notes to Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	37

Item 4.	Disclosure Controls and Procedures	37

Part II. OTHER INFORMATION

Item 1.	Legal Proceedings	38

Item 5.	Other Information	38

Item 6.	Exhibits	40

PART I. FINANCIAL INFORMATION

Item 1.

Consolidated Financial Statements

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)


	March 31, 2007			December 31, 2006
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	583,620		$	462,963
Restricted cash and cash equivalents		218,145			176,827
Interest receivable		6,396			6,642
Accounts receivable		8,146			1,299
Derivative assets		46			—
Prepaid expenses and other		14,990			2,242

TOTAL CURRENT ASSETS		831,343			649,973
NON-CURRENT RESTRICTED CASH AND CASH EQUIVALENTS		900,458			1,071,722
NON-CURRENT RESTRICTED TREASURY SECURITIES		86,304			—
PROPERTY, PLANT AND EQUIPMENT, NET		957,177			748,818
DEBT ISSUANCE COSTS, NET		39,877			41,545
GOODWILL		76,844			76,844
INTANGIBLE ASSETS		4,331			4,331
ADVANCES UNDER LONG-TERM CONTRACTS		14,022			7,101
OTHER		2,005			4,154

TOTAL ASSETS	$	2,912,361		$	2,604,488

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	13,256		$	3,659
Accrued liabilities		118,920			58,280
Derivative liabilities		1,406			—

TOTAL CURRENT LIABILITIES		133,582			61,939
LONG-TERM DEBT		2,357,000			2,357,000
DEFERRED REVENUE		41,000			41,000
OTHER NON-CURRENT LIABILITIES		1,518			1,302
MINORITY INTEREST		262,887			—
COMMITMENTS AND CONTINGENCIES		—			—
STOCKHOLDERS’ EQUITY
Preferred stock, $0.001 par value, 5,000,000 shares authorized, none issued. Common stock, $0.003 par value		—			—
Authorized: 120,000,000 shares at both March 31, 2007 and December 31, 2006
Issued and outstanding: 56,113,685 shares at March 31, 2007 and 55,212,771 shares at December 31, 2006		168			166
Treasury stock, 2,232 shares, at cost		(62	)		—
Additional paid-in-capital		398,004			390,256
Accumulated deficit		(281,697	)		(247,141	)
Accumulated other comprehensive loss		(39	)		(34	)

Total stockholders’ equity		116,374			143,247

Total liabilities and stockholders’ equity	$	2,912,361		$	2,604,488

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(unaudited)


	Three Months Ended March 31,
	2007			2006
Revenues
Oil and gas sales	$	832		$	422
Marketing and trading loss		(2,088	)		—

Total revenues		(1,256	)		422

Operating costs and expenses
LNG receiving terminal and pipeline development expenses		5,754			8,313
Exploration costs		359			838
Oil and gas production costs		67			51
Depreciation, depletion and amortization		1,075			606
General and administrative expenses		21,261			13,181

Total operating costs and expenses		28,516			22,989

Loss from operations		(29,772	)		(22,567	)
Derivative gain		—			761
Interest expense		(26,426	)		(11,138	)
Interest income		21,582			9,544
Other income		—			176

Loss before income taxes and minority interest		(34,616	)		(23,224	)
Income tax benefit		—			7,413

Loss before minority interest		(34,616	)		(15,811	)
Minority interest		60			—

Net loss	$	(34,556	)	$	(15,811	)

Net loss per common share—basic and diluted	$	(0.63	)	$	(0.29	)

Weighted average number of common shares outstanding—basic and diluted		54,891			54,217

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			Accumulated Deficit			Accumulated Other Comprehensive Income (loss)			Total Stockholders’ Equity
	Shares		Amount		Shares		Amount			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (loss)			Total Stockholders’ Equity
Balance—December 31, 2006	55,213		$	166	—		$	—		$	390,256		$	(247,141	)	$	(34	)	$	143,247
Issuances of stock	258			—	—			—			760			—			—			760
Issuances of restricted stock	648			2	—			—			(2	)		—			—			—
Forfeitures of restricted stock	(3	)		—	—			—			—			—			—			—
Stock-based compensation	—			—	—			—			6,990						—			6,990
Treasury stock acquired	—			—	(2	)		(62	)		—			—			—			(62	)
Comprehensive loss:
Foreign currency translation	—			—	—			—			—			—			(5	)		(5	)
Net loss	—			—	—			—			—			(34,556	)		—			(34,556	)

Balance—March 31, 2007	56,116		$	168	(2	)	$	(62	)	$	398,004		$	(281,697	)	$	(39	)	$	116,374

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)


	Three Months Ended March 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(34,556	)	$	(15,811	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		1,075			606
Impairment of unproved properties		334			323
Dry hole expense		8			240
Amortization of debt issuance costs		1,295			918
Non-cash compensation		6,610			5,600
Restricted interest income on restricted cash and cash equivalents		(14,845	)		—
Deferred tax benefit		—			(7,413	)
Non-cash derivative gain		—			(722	)
Minority interest		(60	)		—
Other		(10	)		184
Changes in operating assets and liabilities
Interest receivable		(2	)		—
Other accounts receivable		(7,257	)		281
Prepaid expenses		(12,763	)		(2,014	)
Accounts payable and accrued liabilities		31,715			(2,670	)

NET CASH USED IN OPERATING ACTIVITIES		(28,456	)		(20,478	)

CASH FLOWS FROM INVESTING ACTIVITIES:
LNG terminal and pipeline construction-in-progress		(160,732	)		(73,807	)
Use of restricted cash and cash equivalents		157,183			17,203
Investments in restricted treasury securities		(98,442	)		—
Purchases of fixed assets		(6,234	)		(1,655	)
Additions of oil and gas property		(5	)		(1,954	)
Advances under long-term contracts		(6,920	)		—
Sale of interest in oil and gas prospects		—			448
Other		1,252			(5	)

NET CASH USED IN INVESTING ACTIVITIES		(113,898	)		(59,770	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuances of common units in partnership		164,505			—
Proceeds from issuance of common units to minority owners in partnership		98,442			—
Repayment of Term Loan		—			(1,500	)
Borrowings under Sabine Pass credit facility		—			70,000
Debt issuance costs		(634	)		(2,978	)
Sale of common stock		760			1,164
Purchase of treasury shares		(62	)		(932	)

NET CASH PROVIDED BY FINANCING ACTIVITIES		263,011			65,754

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		120,657			(14,494	)
CASH AND CASH EQUIVALENTS—BEGINNING OF PERIOD		462,963			692,592

CASH AND CASH EQUIVALENTS—END OF PERIOD	$	583,620		$	678,098

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 accompanying unaudited consolidated financial statements of Cheniere Energy, Inc. have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) 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 GAAP 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 wholly-owned or controlled subsidiaries.

Certain reclassifications have been made to conform prior period information to the current presentation including a $179.0 million reclassification between current Restricted Cash and Cash Equivalents and Non-Current Restricted Cash and Cash Equivalents on our December 31, 2006 Consolidated Balance Sheet. The reclassification had no effect on our overall consolidated financial position, results of operations or cash flows.

Interim results are not necessarily indicative of results to be expected for the full fiscal year ending December 31, 2007.

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, 2006.

New Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109 (“FIN No. 48”). FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN No. 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN No. 48. The cumulative effect of applying the provisions of FIN No. 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. We adopted FIN No. 48 in the first quarter of 2007. The adoption of FIN No. 48 had no material impact on our financial position, results of operations or cash flows.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This statement is expected to expand the use of fair value measurement, which is consistent with the FASB’s long-term measurement objectives for accounting for financial instruments. This statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007, although earlier adoption is permitted. Management has not determined the effect that adopting this statement would have on our financial condition or results of operations.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

NOTE 2—Initial Public Offering of Cheniere Energy Partners, L.P. and Minority Interest

On March 26, 2007, Cheniere Energy Partners, L.P. (“Cheniere Partners”) and Cheniere LNG Holdings, LLC (“Holdings”), our wholly-owned subsidiary, completed a public offering of 13,500,000 Cheniere Partners common units (the “Offering”). Cheniere Partners is a Delaware limited partnership formed by us to develop, own and operate the Sabine Pass liquefied natural gas (“LNG”) receiving terminal. Upon the closing of the Offering, the following transactions occurred:

•

Holdings contributed its ownership interests in the entities that directly or indirectly own the Sabine Pass LNG receiving terminal to Cheniere Energy Investments, LLC, a wholly-owned subsidiary of Cheniere Partners;

•

Cheniere Partners issued 21,362,193 common units, 135,383,831 subordinated units, 3,302,045 general partner units (representing a 2% general partner interest) and certain general partner incentive distribution rights to wholly-owned subsidiaries of Cheniere;

•

Cheniere Partners issued 5,054,164 common units to the public and received net proceeds of $98.4 million; and

•

Holdings sold 8,445,836 common units to the public and received net proceeds of $164.5 million, after which Cheniere and the public owned 89.8% and 8.2% limited partner interests in Cheniere Partners, respectively. Holdings also granted the underwriters an option to purchase an additional 2,025,000 of its Cheniere Partners’ common units to cover over-allotments in connection with the Offering (see Note 17—Subsequent Events).

Cheniere Partners used all of the net proceeds of $98.4 million it received to purchase U.S. treasury securities to fund a distribution reserve for payment of initial quarterly distributions of $0.425 per common unit as well as related quarterly distributions to its general partner, through June 30, 2009.

The net proceeds of $164.5 million from the sale of the common units by Holdings and the net proceeds of $39.4 million that it received from the subsequent exercise of the underwriters’ option to purchase additional common units from us (see Note 17—Subsequent Events) are not assets of Cheniere Partners and therefore are unrestricted as to our use.

As of March 31, 2007, our combined general partner and limited partner ownership interests in Cheniere Partners was reduced to approximately 91.8%, before exercise of the underwriters’ over-allotment option. As of such date, we held 135,383,831 subordinated units, 12,916,357 common units and 3,302,045 general partner units of Cheniere Partners. During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the initial quarterly distributions plus any arrearages on the initial quarterly distribution from prior quarters. Our subordinated units do not accrue arrearages. The subordination period generally will end if:

•

Cheniere Partners has earned and paid at least $0.425 on each outstanding common unit, subordinated unit and general partner unit for each of the three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2010; or

•

if Cheniere Partners has earned and paid at least $0.638 (150% of the initial quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for any four consecutive quarters ending on or after June 30, 2008.

The portion of the common units held by the public is presented as a minority interest on our Consolidated Balance Sheets. Losses attributable to the minority interest are presented separately on our Consolidated Statements of Operations based upon the minority interest’s share of Cheniere Partners’ losses calculated in accordance with Cheniere Partners’ partnership agreement.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

The following table sets forth the components of our minority interest balance attributable to third-party investors’ interest in Cheniere Partners as a result of the Offering (in thousands):


Net proceeds from Cheniere Partners’ issuance of common units(1)	$	98,442
Net proceeds from Holdings’ sale of Cheniere Partners common units(2)		164,505
Minority interest share of loss of Cheniere Partners		(60	)

Minority interest at March 31, 2007	$	262,887

(1)

Through the Offering, Cheniere Partners received $98.4 million in proceeds net of offering costs from the issuance of its common units to the public. Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin (“SAB”) No. 51, Accounting for Sales of Stock by a Subsidiary, provides guidance on accounting by the parent for issuances of a subsidiary’s common equity to unaffiliated parties. Under SAB No. 51, a company may elect an accounting policy of recording a gain or loss on the sale of common equity of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the parent’s investment. Upon the conversion of all of our subordinated units in Cheniere Partners to common units, we will evaluate whether to recognize a gain through earnings at that time.

(2)

In conjunction with the Offering, Holdings sold a portion of the Cheniere Partners common units held by it to the public, realizing proceeds net of offering costs of $164.5 million. Due to the existence of our ownership in equity in the partnership having subordinated distribution rights, we have recorded those proceeds as a minority interest. Upon the conversion of all of our subordinated units in Cheniere Partners to common units, we will evaluate whether to recognize a gain through earnings at that time.

NOTE 3—Restricted Cash, Cash Equivalents and Treasury Securities

In August 2006, Cheniere Creole Trail Pipeline, L.P. (“CCTP”), our wholly-owned subsidiary, entered into a purchase order with ILVA S.p.A (“ILVA”) for the purchase of pipe at an aggregate cost of approximately $175.7 million. Associated with this purchase order, CCTP delivered a standby letter of credit to ILVA in the amount of $87.9 million to secure CCTP’s obligations under the purchase order. This letter of credit required a deposit of $87.9 million with the issuer of the letter of credit, which was recorded as Non-Current Restricted Cash and Cash Equivalents on our Consolidated Balance Sheet at December 31, 2006. Once payments by CCTP under the purchase order exceed the value of the letter of credit, ILVA will submit a notice of reduction to the issuing bank to reduce the amount of the letter of credit by 100% of any subsequent payments by CCTP. The Non-Current Restricted Cash and Cash Equivalents cash collateral account on deposit with the issuing bank will be reduced by such amount. In January 2007, CCTP amended the ILVA purchase order to terminate for convenience 610,560 of the 952,700 feet of pipe originally required under the purchase order. The cancellation fee of $0.5 million under the terms of the original purchase order was waived. The amendment called for a decrease to the face amount of the purchase order and the related letter of credit and cash collateral deposit from $87.9 million to $4.1 million. As a result of the amendment, we were able to release the restriction on the cash associated with the reduction of the purchase order.

In November 2006, Sabine Pass LNG, L.P. our wholly-owned subsidiary (“Sabine Pass LNG”), consummated a private offering of an aggregate principle amount of $2 billion of Senior Secured Notes consisting of $550 million of 7¹/4% Senior Secured Notes due 2013 (the “2013 Notes”) and $1.5 billion of 7¹/2% Senior Secured Notes due 2016 (the “2016 Notes” and, collectively with the 2013 Notes, the “Sabine Pass LNG notes”) (see Note 7—Long-Term Debt). Under the terms and conditions of the Sabine Pass LNG notes, we were required to fund cash reserve accounts for approximately $335 million related to future interest payments through May 2009 and approximately $887 million to pay the remaining costs to complete the initial phase (“Phase 1”) and the first stage of the second phase (“Phase 2–Stage 1”) of the Sabine Pass LNG receiving terminal. These cash accounts are controlled by a collateral trustee, and therefore, are shown as restricted cash and cash

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

equivalents on our Consolidated Balance Sheet. As of March 31, 2007 and December 31, 2006, $209.6 million and $176.3 million, respectively, related to future interest payments due within one year and accrued construction costs have been classified as a current asset, and $895.1 million and $982.6 million, respectively, related to remaining construction costs and future interest payments due beyond one year have been classified as a non-current asset on our Consolidated Balance Sheet.

As discussed above in Note 2 at the closing of the Offering, we funded a distribution reserve for $98.4 million, which was invested in U.S. treasury securities. The distribution reserve, including interest earned thereon, will be used to pay quarterly distributions of $0.425 per common unit for all common units, as well as related distributions to Cheniere Partners’ general partner, through June 30, 2009. The U.S. treasury securities were acquired at a discount from their maturity values equal to an average of approximately 4.87% per year. As of March 31, 2007, we have classified $86.3 million of the U.S. treasury securities as Non-Current Restricted Treasury Securities on our Consolidated Balance Sheet as these securities have maturities greater than three months. The remaining $12.1 million invested in U.S. treasury securities are classified as Non-Current Restricted Cash and Cash Equivalents on our Consolidated Balance Sheet as of March 31, 2007, as these securities have maturities less than or equal to three months.

NOTE 4—Property, Plant and Equipment

Property, plant and equipment consists 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, 2007			December 31, 2006
LNG TERMINAL COSTS
LNG terminal construction-in-progress	$	802,618		$	684,008
LNG site and related costs, net		1,466			1,467

Total LNG terminal costs		804,084			685,475

NATURAL GAS PIPELINE COSTS
Pipeline construction-in-progress		125,894			45,615
Pipeline right-of-ways		5,156			2,134

Total natural gas pipeline costs		131,050			47,749

OIL AND GAS PROPERTIES, successful efforts
Proved		2,340			2,343
Unproved		445			779
Accumulated depreciation, depletion and amortization		(350	)		(263	)

Total oil and gas properties, net		2,435			2,859

FIXED ASSETS
Computer and office equipment		6,316			5,352
Furniture and fixtures		1,417			1,310
Computer software		8,465			8,043
Leasehold improvements		2,298			2,206
Projects in progress		7,932			1,724
Other		188			123
Accumulated depreciation		(7,008	)		(6,023	)

Total fixed assets, net		19,608			12,735

PROPERTY, PLANT AND EQUIPMENT, NET	$	957,177		$	748,818

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

LNG Terminal Costs

Once an LNG receiving terminal is placed into service, the related LNG terminal construction-in-progress costs will be depreciated using the straight-line depreciation method. We are in the process of determining the appropriate approach for grouping identifiable components with similar estimated useful lives. Estimated useful lives for components, once construction is completed, are currently estimated to range between 10 and 50 years.

In February 2005 and July 2006, Phase 1 and Phase 2—Stage l, respectively, of the Sabine Pass LNG receiving terminal project satisfied our criteria for capitalization. Accordingly, costs associated with the construction of Phase 1 and Phase 2—Stage 1 of the Sabine Pass LNG receiving terminal have been capitalized as construction-in-progress since those dates. For the three months ended March 31, 2007 and 2006, we capitalized $12.9 million and $2.1 million of interest expense related to these construction projects, respectively. In March 2006, our Corpus Christi LNG receiving terminal satisfied the criteria for capitalization. Accordingly, costs associated with the initial site work for the Corpus Christi LNG receiving terminal have been capitalized as construction-in progress since that time. For the three months ended March 31, 2007, we capitalized $0.3 million of interest expense related to this construction project.

Natural Gas Pipeline Costs

Our developing natural gas pipeline business is subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and we have determined that our pipelines to be constructed have met the criteria set forth in SFAS No. 71, Accounting for the Effects of Certain Types of Regulations. Accordingly, we began applying the provisions of SFAS No. 71 to the affected pipeline subsidiaries in the second quarter of 2006. Natural gas pipeline costs also include amounts capitalized as Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service. For the three months ended March 31, 2007, we capitalized $1.3 million of AFUDC to our natural gas pipeline projects.

Fixed Assets

Our fixed assets are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets. Depreciation expense related to our property, plant and equipment totaled $1.0 million for the three months ended March 31, 2007.

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. As of March 31, 2007 and December 31, 2006, we had unrecorded cumulative suspended losses of $14.7 million and $13.0 million, respectively, related to our investment in Freeport LNG, as the basis in this investment had been reduced to zero. As a result, we did not record our share of the losses of the partnership for the three months ended March 31, 2007 because we had not guaranteed any obligations and are not committed to provide any further financial support, and have not done so since December 2005.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

The financial position of Freeport LNG at March 31, 2007 and December 31, 2006 and the results of Freeport LNG’s operations for the three months ended March 31, 2007 and 2006 are summarized as follows (in thousands):


	March 31, 2007			December 31, 2006
Current assets	$	259,127		$	294,847
Construction-in-progress		660,180			594,191
Fixed assets, net, and other assets		9,707			9,684

Total assets	$	929,014		$	898,722

Current liabilities	$	35,314		$	38,621
Notes payable		942,650			903,369
Deferred revenue and other deferred credits		5,645			5,666
Partners’ capital		(54,595	)		(48,934	)

Total liabilities and partners’ capital	$	929,014		$	898,722


	Three Months Ended March 31,
	2007			2006
Loss from continuing operations	$	(5,661	)	$	(10,585	)
Net loss		(5,661	)		(10,585	)
Cheniere’s 30% equity in net loss from limited partnership(1)		(1,698	)		(3,175	)

(1)	As discussed above, we did not record the $1.7 million and $3.2 million losses in our Consolidated Statement of Operations for the three months ended March 31, 2007 and 2006 because our investment basis was zero.

NOTE 6—Accrued Liabilities

Accrued liabilities consisted of the following (in thousands):


	March 31, 2007		December 31, 2006
LNG terminal construction costs	$	40,060	$	16,334
Accrued interest expense and related fees		60,790		24,861
Pipeline construction costs		3,534		7,039
Debt issuance costs		—		783
Payroll		2,967		5,512
Professional and legal services		608		—
Purchased physical gas		5,760		—
Projects-in-progress		1,580		1,067
Other accrued liabilities		3,621		2,684

Accrued liabilities	$	118,920	$	58,280

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

NOTE 7—Long-Term Debt

As of March 31, 2007 and December 31, 2006, our long-term debt consisted of the following (in thousands):


	March 31, 2007		December 31, 2006
Sabine Pass LNG notes	$	2,032,000	$	2,032,000
Convertible Senior Unsecured Notes		325,000		325,000

Total Long-Term Debt	$	2,357,000	$	2,357,000

Sabine Pass LNG Notes

In November 2006, Sabine Pass LNG, consummated a private offering of an aggregate principal amount of $2,032 million of Sabine Pass LNG notes, consisting of $550 million of the 2013 notes and $1,482 million of the 2016 notes. Sabine Pass LNG has filed a registration statement with the SEC offering to exchange the unregistered Sabine Pass LNG notes for a like amount of senior secured notes of Sabine Pass LNG which are registered under the Securities Act of 1933, as amended (“Securities Act”).

Interest on the Sabine Pass LNG notes is payable semi-annually in arrears on May 30 and November 30 of each year, beginning May 30, 2007. The Sabine Pass LNG notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG’s equity interests and substantially all of its operating assets.

Under the indenture governing the Sabine Pass LNG notes, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied. The indenture requires that Sabine Pass LNG apply its net operating cash flow (i) first, to fund with monthly deposits its next semiannual payment of approximately $75.5 million of interest on the Sabine Pass LNG notes, and (ii) second, to fund a one-time, permanent debt service reserve fund equal to one semiannual interest payment of approximately $75.5 million on the Sabine Pass LNG notes. Distributions from Sabine Pass LNG will be permitted only after Phase 1 target completion, as defined in the indenture governing the Sabine Pass LNG notes, or such earlier date as project revenues are received, upon satisfaction of the foregoing funding requirements, after satisfying a fixed charge coverage ratio test of 2:1 and after satisfying other conditions specified in the indenture.

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 at any time into our common stock under certain circumstances at an initial conversion rate of 28.2326 per $1,000 principal amount of the notes, which is equal to a conversion price of approximately $35.42 per share. We may redeem some or all of the notes on or before August 1, 2012, for cash equal to 100% of the principal plus any accrued and unpaid interest if in the previous 10 trading days the volume-weighted average price of our common stock exceeds $53.13, subject to adjustment, for at least five consecutive trading days. In the event of such a redemption, we will make an additional payment equal to the present value of all remaining scheduled interest payments through August 1, 2012, discounted at the U.S. Treasury rate plus 50 basis points. The indenture governing the notes contains customary reporting requirements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

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 was recorded as a reduction to Additional Paid-in-Capital in accordance with the guidance of 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 $239.8 million, after deducting the cost of the hedge transactions, the underwriting discount and related fees. As of March 31, 2007, no holders had elected to convert their notes.

NOTE 8—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 Sheets for Cash and Cash Equivalents, Accounts Receivable and Accounts Payable approximate fair value due to their short-term nature. We use available market 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.

Financial Instruments (in thousands):


	March 31, 2007				December 31, 2006
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2013 Notes (1)	$	550,000	$	554,125	$	550,000	$	547,250
2016 Notes (1)		1,482,000		1,489,410		1,482,000		1,478,295
2.25% Convertible Senior Unsecured Notes due 2012 (2)		325,000		349,577		325,000		334,750
Restricted Treasury Securities (3)		98,442		98,442		—		—

(1)	The fair value of the Sabine Pass LNG notes was based on quotations obtained from broker-dealers who made markets in these and similar instruments as of March 30, 2007 and December 29, 2006 .

(2)	The fair value of our Convertible Senior Unsecured Notes is based on a closing trading price on March 30, 2007 and December 29, 2006.

(3)

The fair value of our Restricted Treasury Securities was based on quotations obtained from broker-dealers who made markets in these and similar instruments as of March 30, 2007. This amount includes $12.1 million classified as Non-Current Restricted Cash and Cash Equivalents on our Consolidated Balance Sheet as of March 31, 2007, as these securities have maturities less than or equal to three months.

NOTE 9—Income Taxes

From our inception, we have reported net operating losses (“NOL”) for both financial reporting purposes and for international, federal and state income tax reporting purposes. Accordingly, we are not presently a taxpayer and have not recorded a net liability for international, 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, 2007 and 2006 included deferred income tax benefits of zero and $7.4 million, respectively. The deferred income tax benefit recorded for the three months ended March 31, 2006 was provided in accordance with the guidance in paragraph 140 of SFAS No. 109 and EITF Abstract, Topic D-32, which, in certain circumstances, requires items reported in pre-tax accumulated other comprehensive income (“OCI”) to be considered in the determination of the amount of tax benefit that must be reported in the Consolidated Statement of Operations when an NOL occurs. In our situation, the specific circumstance related to a pre-tax accumulated

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

OCI of $27.0 million recorded as of March 31, 2006 in connection with our interest rate swaps. The deferred tax benefit for the three months ended March 31, 2006 represents the portion of the change in our tax asset valuation account that was allocable to the deferred income tax on the pre-tax income items reported in accumulated OCI in our March 31 ,2006 Consolidated Statement of Stockholders’ Equity.

The income tax benefit included in our reported net loss consisted of the following (in thousands):


	Three Months Ended March 31,
	2007		2006
Current income tax expense	$	—	$	—
Deferred income tax benefit		—		7,413

	$	—	$	7,413

A substantial portion of the Sabine Pass LNG receiving terminal qualifies for the 50% bonus depreciation allowance enacted by the Gulf Opportunity Zone Act of 2005. These accelerated deductions are based on a full year estimate of the Sabine Pass LNG receiving terminal qualifying additions that will be ready to be placed in service during the remainder of 2007. The accelerated tax depreciation deduction offsets a substantial portion of the first quarter tax gain resulting from the Offering.

In May 2006, the State of Texas enacted a new business tax that is imposed on gross revenues to replace the State’s current franchise tax regime. The new legislation’s effective date is January 1, 2008, which means that our first Texas margins tax (“TMT”) return will not become due until May 15, 2008 and will be based on our 2007 operations. Although the TMT is imposed on an entity’s gross revenues rather than on its net income, certain aspects of the tax make it similar to an income tax. In accordance with the guidance provided in SFAS No. 109, we have properly determined the impact of the newly-enacted legislation in the determination of our reported state current and deferred income tax liability.

New Accounting Pronouncement

In July 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109. FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition rules.

The provisions of FIN No. 48 have been applied to all of our material tax positions taken through the date of adoption and during the interim quarterly period ended March 31, 2007. We have determined that all of our material tax positions taken in our income tax returns and the positions we expect to take in our future income tax filings meet the more likely-than-not recognition threshold prescribed by FIN No. 48. In addition, we have also determined that, based on our judgment, none of these tax positions meet the definition of “uncertain tax positions” that are subject to the non-recognition criteria set forth in the new pronouncement.

Our federal consolidated income tax returns have not been audited by the Internal Revenue Service; we have not been notified of any pending federal, state or international income tax audits, and we are not aware of any

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

income tax controversies that are likely to occur with any taxing authority. We have not entered into any agreements with any taxing authorities to extend the period of time in which they may assert or assess additional income tax, penalties or interest. However, because we are presently in an NOL carryover position and have been since our inception, under the applicable Internal Revenue Service guidelines, in the event of an audit, our available federal NOL carryover amount is subject to adjustment until the normal three year federal statute of limitations closes for the year in which the NOL is fully utilized. The Texas Comptroller’s office recently completed an audit of Cheniere’s Texas franchise tax returns for the three year period ended December 31, 2004; the Louisiana Department of Revenue recently completed an income and franchise audit of Cheniere and one of our wholly-owned affiliates for the two year period ended December 31, 2003. We expect that all of our significant operating affiliates will be audited by the States of Texas and Louisiana for annual tax reporting periods ended on or before December 31, 2004. To date, all of the state-level income tax audits have been settled favorably and without changes. None of our foreign affiliates have been audited by any foreign taxing authorities and none have been notified of any pending tax audits.

As discussed above, we have not previously recorded a liability for international, federal or state income taxes, and therefore, we have not been subject to any penalties or interest expense related to any income tax liabilities. In future reporting periods, if any interest or penalties are imposed in connection with an income tax liability, we expect to include both of these items in the our income tax provision.

As set forth in SFAS No. 109, we have established a tax valuation allowance for the tax benefits related to our NOL carryover and our other deferred tax assets due to the uncertainty of realizing the tax benefits. If, as a result of a change in facts, any of our previously recognized tax benefits are required to be de-recognized in a future reporting period, the resulting decrease in tax benefits will be taken into account before the amount of our tax valuation allowance is established. We do not believe that it is reasonably possible that the amount of our unrecognized tax benefits will change significantly within the next twelve months. To date, the adoption of FIN No. 48 has had no impact on our financial position, results of operations or cash flows.

NOTE 10—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 our earnings.

The following table reconciles basic and diluted weighted average common shares outstanding for the three months ended March 31, 2007 and 2006 (in thousands except for loss per share):


	Three Months Ended March 31,
	2007			2006
Weighted average common shares outstanding:
Basic		54,891			54,217
Dilutive common stock options		—			—
Dilutive Convertible Senior Unsecured Notes		—			—

Diluted		54,891			54,217

Basic loss per share	$	(0.63	)	$	(0.29	)
Diluted loss per share	$	(0.63	)	$	(0.29	)

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

NOTE 11—Other Comprehensive Income (Loss)

The following table is a reconciliation of our net loss to our comprehensive loss for the three months ended March 31, 2007 and 2006 (in thousands):


	Three Months Ended March 31,
	2007			2006
Net loss	$	(34,556	)	$	(15,811	)
Other comprehensive income (loss) items:
Cash flow hedges, net of income tax		—			13,768
Foreign currency translation		(5	)		—

Comprehensive loss	$	(34,561	)	$	(2,043	)

NOTE 12—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 that could be provided by Western for such services was owned by Bramblebush, L.L.C. (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 expenses of $111,000 related to the charter of the Challenger 600 aircraft owned by the LLC. For the three months ended March 31, 2007, there were no expenses incurred related to such aircraft.

NOTE 13—Commitments and Contingencies

Amended Pipe Purchase Order

In January 2007, CCTP amended the ILVA purchase order to terminate for convenience 610,560 of the 952,700 feet of pipe originally required under the purchase order, as amended. The cancellation fee of $0.5 million under the terms of the original purchase order was waived. The amendment calls for a decrease in the face amount of the purchase order and the related letter of credit and cash collateral deposit from $87.9 million to $4.1 million. As a result, $4.1 million is included in Non-current Restricted Cash and Cash Equivalents on our Consolidated Balance Sheets.

Pipe Coating Purchase Order

In January 2007, CCTP entered into a purchase order with The Bayou Companies, LLC (“Bayou”) for concrete weight coating on approximately 43 miles of the Creole Trail Pipeline. Payments made by CCTP to Bayou for work performed under the purchase order are not expected to exceed $22.3 million. CCTP may at any time terminate, for convenience, Bayou’s performance to be effective upon receipt of a written notice and payment for items provided or services performed prior to termination. Such work commenced in March 2007 and is expected to be fully completed in July 2007.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

Pipeline Construction Agreements

In January 2007, CCTP entered into a construction agreement with Sheehan Pipe Line Construction Company (“Sheehan”) for the construction of approximately 36 miles of Phase 1 of the Creole Trail Pipeline (consisting of 78 miles of natural gas pipeline). Under the terms of the agreement, Sheehan will provide CCTP with equipment, labor, inspection, manufacture, fabrication, installation, delivery, transportation, storage, assembly and construction services in connection with the Creole Trail pipeline. Payments anticipated to be made by CCTP to Sheehan for work performed under the agreement are not expected to exceed $65.6 million with a 5% retainage that is held back from each invoice to be paid upon final completion. CCTP may at any time terminate, for convenience, Sheehan’s performance effective upon receipt of a written notice by Sheehan and payment for items provided or services performed prior to termination. Such work is expected to commence in July 2007 and is expected to be fully complete in March 2008.

In January 2007, CCTP entered into an agreement with Sunland Construction, Inc. (“Sunland”) for the construction of approximately 23 miles of Phase 1 of the Creole Trail Pipeline. Under the terms of the agreement, Sunland will provide CCTP with equipment, labor, inspection, manufacture, fabrication, installation, delivery, transportation, storage, assembly and construction services in connection with the Creole Trail Pipeline. Payments by CCTP to Sunland under the agreement are not expected to exceed $70.1 million, with a 5% retainage held back from each invoice to be paid upon final completion. CCTP may at any time terminate, for convenience, Sunland’s performance effective upon receipt of a written notice by Sunland and payment for items provided or services performed prior to termination. The agreement is subject to a cancellation fee not to exceed 5% of the estimated contract price. Such work is expected to commence in April 2007 and is expected to be fully complete in May 2008.

In March 2007, CCTP entered into an agreement with Sunland for the construction of approximately 18 miles of the Creole Trail Pipeline. Under the terms of the agreement, Sunland will provide CCTP with equipment, labor, inspection, manufacture, fabrication, installation, delivery, transportation, storage, assembly and construction services in connection with the Creole Trail Pipeline. Payments by CCTP to Sunland under the agreement are not expected to exceed $43.6 million, with a 5% retainage held back from each invoice to be paid upon final completion. CCTP may at any time terminate, for convenience, Sunland’s performance effective upon receipt of a written notice by Sunland, payment for items provided or services performed prior to termination. The agreement is subject to a cancellation fee not to exceed 2% of the estimated contract price. Such work is expected to commence in June 2007 and is expected to be fully complete in May 2008.

NOTE 14—Supplemental Cash Flow Information and Disclosures of Non-Cash Transactions

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


	Three Months Ended March 31,
	2007		2006
Cash paid for interest, net of amounts capitalized	$	3,656	$	13,106
Construction-in-progress additions recorded as accrued liabilities	$	52,544	$	16,525

NOTE 15—Business Segment Information

We have four business segments: LNG receiving terminal, natural gas pipeline, LNG and natural gas marketing and oil and gas exploration and development. These segments reflect lines of business for which

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

separate financial information is produced internally and are subject to evaluation by our chief operating decision makers in deciding how to allocate resources.

Our LNG receiving terminal segment is in various stages of developing three LNG receiving terminal projects along the U.S. Gulf Coast at the following locations: Sabine Pass LNG, approximately 91.8% owned (as of March 31, 2007), in western Cameron Parish, Louisiana on the Sabine Pass Channel; Corpus Christi LNG, 100% owned, near Corpus Christi, Texas; and Creole Trail LNG, 100% owned, at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. In addition, we own a 30% limited partner interest in a fourth project, Freeport LNG, located on Quintana Island near Freeport, Texas.

Our natural gas pipeline segment is in various stages of developing three, 100% owned, natural gas pipelines in connection with our three LNG receiving terminals to provide access to North American natural gas markets.

Our LNG and natural gas marketing segment is in its early stages of development. We intend to purchase LNG from foreign suppliers, arrange transportation of LNG to our network of LNG receiving terminals and other terminals, utilize our revaporization capacity at our LNG receiving terminals and other terminals to revaporize imported LNG, arrange the transportation of revaporized natural gas through our pipelines and other interconnected pipelines, and sell natural gas to buyers. To develop our capacity to resell revaporized natural gas in the future, we are engaged in domestic natural gas purchase and sale, transportation and storage transactions, including financial derivative transactions, as part of our marketing activities.

Our oil and gas exploration and development segment conducts and participates in exploration, development and production activities focused in the shallow waters of the Gulf of Mexico.

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


	Segments
	LNG Receiving Terminal			Natural Gas Pipeline			LNG & Natural Gas Marketing			Oil & Gas Exploration and Development			Corporate and Other(1)			Total Consolidated
As of or for the three months ended March 31, 2007:
Revenues	$	—		$	—		$	(2,088	)	$	832		$	—		$	(1,256	)
Net income (loss) from operations		(6,574	)		(528	)		(5,956	)		332			(17,046	)		(29,772	)
Total assets		2,269,084			131,844			51,265			2,959			457,209			2,912,361

As of or for the three months ended March 31, 2006:
Revenues	$	—		$	—		$	—		$	422		$	—		$	422
Net loss from operations		(8,840	)		(1,669	)		(1,235	)		(978	)		(9,845	)		(22,567	)
Total assets		839,326			800			685			3,263			488,277			1,332,351

(1)	Includes corporate activities and certain intercompany eliminations.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

NOTE 16—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”). Effective January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share-Based Payment, which revised SFAS No. 123 and superseded Accounting Principles Bulletins (“APB”) No. 25. No adjustments to prior periods were made as a result of adopting SFAS No. 123R. 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.

For the three months ended March 31, 2007 and 2006, the total stock-based compensation expense (net of capitalization) recognized in our net loss was $6.6 million and $5.6 million, respectively. For the three months ended March 31, 2007 and 2006, the total stock-based compensation cost capitalized as part of the cost of capital assets was $0.4 million and $0.3 million, respectively.

The total unrecognized compensation cost at March 31, 2007 relating to non-vested share-based compensation arrangements granted under the 1997 Plan and 2003 Plan, before any capitalization, was $78.6 million. That cost is expected to be recognized over five years, with a weighted average period of 1.8 years.

SFAS No. 123R has no current effect on net cash flow. Once we become a taxpayer, we will recognize 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 $0.8 million and $1.2 million in the three months ended March 31, 2007 and 2006, respectively.

Stock Options

During the first three months of 2007, there were no options issued to purchase shares of our common stock under the 2003 Plan.

We estimate the fair value of stock options under SFAS No. 123R at the date of grant using a Black-Scholes valuation model, which is consistent with the valuation technique we previously utilized to value stock options for the footnote disclosures required under SFAS No. 123. The following table provides the weighted average assumptions used in the Black-Scholes stock option valuation model to value stock options granted in the three months ended March 31, 2007 and 2006, respectively. 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 stock options granted in 2007 is based on the “simplified” method of estimating expected term for “plain vanilla” stock options allowed by SAB No. 107, Valuation of Share-based Payment Agreements for Public Companies, and varies based on the vesting period and contractual term of the stock option. Expected volatility for stock options granted in 2007 is based on an equally weighted average of the implied volatility of exchange traded stock 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 stock option’s expected life. We have not declared dividends on our common stock.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

The table below provides a summary of stock option activity under the combined plans as of March 31, 2007, and changes during the three months then ended:


	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)					(in thousands)
Outstanding at January 1, 2007	5,187		$	34.25
Granted	—			—
Exercised	(264	)		27.77
Forfeited or Expired	(16	)		31.63

Outstanding at March 31, 2007	4,907		$	35.91	7.2	$	24,292

Exercisable at March 31, 2007	1,211		$	16.55	4.2	$	19,224

Effective March 28, 2007, we amended certain existing stock option grants to provide for acceleration of vesting upon termination, under certain circumstances, within one year of a change of control event; or upon the death or disability of the stock option holder. We believe that the adoption of this amendment did not have an impact on stock options ultimately expected to vest, and, therefore, did not have a current impact on our financial position, results of operations or cash flows.

Stock and Non-Vested Stock

We have granted stock and non-vested stock to employees, executive officers and outside directors under the 2003 Plan. Under SFAS No. 123R, grants of non-vested stock are accounted for on an intrinsic value basis. No recognition of deferred compensation is made in stockholders’ equity. 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.

In January 2007, 628,396 shares having three-year graded vesting were issued to our employees and executive officers in the form of non-vested (restricted) stock awards related to our performance in 2006. In the three months ended March 31, 2007, a total of 51,564 shares of non-vested stock having four-year graded vesting were issued to new and existing employees.

The table below provides a summary of the status of our non-vested shares under the 2003 Plan as of March 31, 2007, 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, 2007	555		$	33.97
Granted (1)	680			27.78
Vested	(28	)		37.89
Forfeited	(4	)		30.00

Non-vested at March 31, 2007	1,203		$	30.39

(1)	Includes awards of 31,500 non-vested shares granted under the French Addendum to the 2003 Plan, which were not issued and outstanding at March 31, 2007.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

Share-Based Plan Descriptions and Information

Our 1997 Plan provides for the issuance of stock options to purchase up to 5.0 million shares of our common stock, all of which have been granted. Non-qualified stock options were granted to employees, contract service providers and outside directors. Terms for the remaining unexercised stock options are five years with vesting that generally occurs on a graded basis over three years.

Our 2003 Plan provides for the issuance of up to an aggregate of 11.0 million shares of our common stock. 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 of our Board of Directors 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 17—Subsequent Events

On April 16, 2007, the underwriters of the Offering exercised their over-allotment option to purchase 2,025,000 additional common units, which resulted in net proceeds of approximately $39 million to Holdings as the selling unitholder, and reduced our overall ownership interest in Cheniere Partners to approximately 90.6%.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INFORMATION 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 fact, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

•

statements relating to the construction and operation of each of our proposed liquefied natural gas (“LNG”) receiving terminals or our proposed pipelines, or expansions or extensions thereof, including statements concerning the completion or expansion thereof by certain dates or at all, the costs related thereto and certain characteristics, including amounts of regasification and storage capacity, the number of storage tanks and docks, pipeline deliverability and the number of pipeline interconnections, if any;

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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;

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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 are, or may become subject to, TUAs or other contracts;

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statements regarding counterparties to our TUAs, construction contracts and other contracts;

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

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

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

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

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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.

As used herein, the terms “Cheniere,” “we,” “our” and “us” refer to Cheniere Energy, Inc. and its wholly-owned or controlled subsidiaries.

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 under “Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2006. 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.

BUSINESS AND OPERATIONS

General

We are currently 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 developing a business to market LNG and natural gas. To a limited extent, we are also engaged in oil and natural gas exploration and development activities in the Gulf of Mexico. We operate four business activities: LNG receiving terminal, natural gas pipeline, LNG and natural gas marketing, and oil and gas exploration and development.

LNG Receiving Terminal Business

We have focused our LNG receiving terminal development efforts on the following three projects: the Sabine Pass LNG receiving terminal in western Cameron Parish, Louisiana on the Sabine Pass Channel; the Corpus Christi LNG receiving terminal near Corpus Christi, Texas; and the Creole Trail LNG receiving terminal at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana.

Our ownership interest in the Sabine Pass LNG receiving terminal is held through Cheniere Energy Partners, L.P. (“Cheniere Partners”), a Delaware limited partnership, in which we hold an approximate 90.6% interest as a result of the recent completion of an initial public offering of common units in Cheniere Partners as well as the exercise of the underwriters’ option to purchase additional common units in Cheniere Partners. In turn, Cheniere Partners owns a 100% interest in Sabine Pass LNG, L.P. (“Sabine Pass LNG”), which is currently developing the Sabine Pass LNG receiving terminal. We currently own 100% interests in the Corpus Christi and Creole Trail LNG receiving terminals. In addition, we own a 30% interest in a fourth project, Freeport LNG, located on Quintana Island near Freeport, Texas. The three LNG receiving terminals under development by us have an aggregate designed regasification capacity of approximately 10 billion cubic feet per day (“Bcf/d”), subject to expansion. Sabine Pass LNG has entered into long-term TUAs with Total LNG USA, Inc. (“Total”), Chevron USA, Inc. (“Chevron”) and Cheniere Marketing, Inc. (“Cheniere Marketing”), our wholly-owned subsidiary, for regasification capacity at the Sabine Pass LNG receiving terminal.

Construction of the Sabine Pass LNG receiving terminal commenced in March 2005, and we anticipate commencing operations during the second quarter of 2008. We will contemplate making a final investment decision to complete construction of the Corpus Christi LNG receiving terminal and commence construction of the Creole Trail LNG receiving terminal upon, among other things, achieving acceptable commercial arrangements and arranging appropriate financing.

Natural Gas Pipeline 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. We anticipate that construction of the Sabine Pass Pipeline will commence in the second quarter of 2007 and that operations will commence in the fourth quarter of 2007. We anticipate that construction of Phase 1 of the Creole Trail Pipeline (consisting of 78 miles of natural gas pipeline) will commence in the second quarter of 2007 and that Phase 1 operations will commence in the second quarter of 2008. Construction contracts for the Corpus Christi Pipeline have not been negotiated.

LNG and Natural Gas Marketing Business

Our LNG and natural gas marketing business is in its early stages of development. We intend to purchase LNG from foreign suppliers, arrange the transportation of LNG to our network of LNG receiving terminals, utilize Cheniere Marketing’s capacity at our LNG receiving terminals to revaporize imported LNG, arrange the transportation of revaporized natural gas through our pipelines and other interconnected pipelines, and sell natural gas to buyers. Alternatively, we may purchase LNG from foreign suppliers and sell the LNG to foreign purchasers if more favorable economic conditions exist in those markets. To develop our capability to resell revaporized natural gas in the future, we are engaging in domestic natural gas purchase and sale, transportation and storage transactions, including financial derivative 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 production activities focused in the shallow waters of the Gulf of Mexico.

LIQUIDITY AND CAPITAL RESOURCES

We are primarily engaged in LNG-related business activities. Our three LNG receiving 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.

We have obtained financing and approval of our board of directors to construct the following projects, as more fully described below: Phase 1 and Phase 2–Stage 1 of the Sabine Pass LNG receiving terminal; the Sabine Pass Pipeline; and Phase 1 of the Creole Trail Pipeline. The estimated costs of these projects, before financing costs, are, respectively, $1.4 billion to $1.5 billion, $100 million, and $400 million to $450 million.

As of March 31, 2007, we had an unrestricted Cash and Cash Equivalents balance of $583.6 million. In addition, we have $1.2 billion in Restricted Cash, Cash Equivalents and U.S. treasury securities, including $738.8 million for the remaining construction costs of the initial phase (“Phase 1”) and the first stage of the second phase (“Phase 2–Stage 1”) of the Sabine Pass LNG receiving terminal, $353.7 million for interest payments through May 2009 related to the Sabine Pass LNG notes and $98.4 million for cash distributions through June 2009 to the common unitholders of Cheniere Partners and related distributions to its general partner. As a result, we believe that we have adequate financial resources available to us to implement the currently approved projects described above. Our LNG-related business activities are not expected to begin to operate and generate significant cash flows before 2008.

Our LNG Receiving Terminals

Sabine Pass LNG

Customer TUAs

Each of the customers at the Sabine Pass LNG receiving terminal must make capacity payments under its TUA on a “firm commitment” basis, which means that the customer will be obligated to pay the full contracted amount of monthly capacity fees whether or not it uses any of its reserved capacity. Provided the Sabine Pass LNG receiving terminal has achieved commercial operation at 2.0 Bcf/d, which we expect will occur during the second quarter of 2008, these “firm commitment” TUA payments will be made by the following customers:

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Total has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years commencing April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions;

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Chevron has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years commencing not later than July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron; and

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Cheniere Marketing has reserved approximately 2.0 Bcf/d of regasification capacity, is entitled to use any capacity not utilized by Total and Chevron and has agreed to make monthly payments to Sabine Pass LNG aggregating approximately $250 million per year for at least 19 years commencing January 1, 2009, plus payments of $5 million per month during an initial commercial operations ramp-up period in 2008. We have guaranteed Cheniere Marketing’s obligations under its TUA.

Each of Total and Chevron has paid us $20 million in nonrefundable advance capacity reservation fees, which will be amortized over a 10-year period as a reduction of each customer’s regasification capacity fees payable under its TUA.

Construction of Receiving Terminal

The Sabine Pass LNG terminal is being constructed in two phases. Phase 1 of the Sabine Pass LNG receiving terminal was designed with an initial regasification capacity of 2.6 Bcf/d and three LNG storage tanks with an aggregate LNG storage capacity of 10.1 billion cubic feet (“Bcf”). Construction of Phase 1 began in March 2005. We estimate the cost to construct Phase 1 of the Sabine Pass LNG receiving terminal will be approximately $900 million to $950 million, before financing costs. As of March 31, 2007, we had paid $615.0 million of Phase 1 construction costs.

Phase 2–Stage 1 of the development of the Sabine Pass LNG receiving terminal is designed to increase the regasification capacity from 2.6 Bcf/d to 4.0 Bcf/d by adding two LNG storage tanks, additional vaporizers and related facilities. We estimate the cost to construct Phase 2–Stage 1 of the Sabine Pass LNG receiving terminal will be approximately $500 million to $550 million, before financing costs. As of March 31, 2007, we had paid $73.5 million of Phase 2–Stage 1 construction costs.

We estimate that the aggregate cost to complete construction of Phase 1 and Phase 2–Stage 1 of the Sabine Pass LNG receiving terminal will be approximately $1.4 billion to $1.5 billion, before financing costs. Our cost estimates are subject to change due to such items as cost overruns, change orders, increased component and material costs, escalation of labor costs and increased spending to maintain our construction schedule.

We will fund our construction period capital resource requirements from a portion of the $2,032 million in net proceeds received from Sabine Pass LNG’s issuance in November 2006 of senior secured notes (the “Sabine Pass LNG notes”). We placed $335 million of the net proceeds in a reserve account to fund scheduled interest payments on the Sabine Pass LNG notes through May 2009. We also placed approximately $887 million in a construction account, which, until satisfaction of construction completion milestones, will only be applied to pay construction and startup costs of the Sabine Pass LNG receiving terminal and to pay other expenses incidental for us to complete construction of the project. We used the remaining net proceeds received from the issuance of the Sabine Pass LNG notes to repay indebtedness of Sabine Pass LNG, to make a distribution to Cheniere LNG Holdings, LLC (“Holdings”), our wholly-owned subsidiary, for the repayment of its outstanding term loan and to pay fees and expenses related to the issuance of the Sabine Pass LNG notes.

Phase 1 EPC Agreement

In December 2004, Sabine Pass LNG entered into a lump-sum turnkey engineering, procurement and construction (“EPC”) agreement with Bechtel Corporation (“Bechtel”) for Phase 1 of the Sabine Pass LNG receiving terminal. Except for certain third-party work specified in the EPC agreement, the work to be performed by Bechtel includes all of the work required to achieve substantial completion and final completion of Phase 1 of the Sabine Pass LNG receiving terminal in accordance with the requirements of the EPC agreement. Pursuant to the EPC agreement, Sabine Pass LNG agreed to pay Bechtel a contract price of $646.9 million plus certain reimbursable costs for the work performed under the EPC agreement. This contract price is subject to adjustment for certain costs of materials, contingencies, change orders and other items. As of April 30, 2007, change orders for $132.3 million had been approved, primarily for design changes, increases in costs of materials, insurance costs and costs related to the 2005 hurricanes, increasing the total contract price to $779.2 million.

Phase 2–Stage 1 Construction Agreements

In July 2006, Sabine Pass LNG entered into three construction agreements to facilitate construction of the Phase 2–Stage 1 expansion, as follows:

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EPCM Agreement. Sabine Pass LNG entered into an engineering, procurement, construction and management (“EPCM”) agreement with Bechtel pursuant to which Bechtel will provide: design and

engineering services for Phase 2–Stage 1 of the Sabine Pass LNG receiving terminal project, except for such portions to be designed by other contractors and suppliers that Sabine Pass LNG contracts with directly; construction management services to manage the construction of the Sabine Pass LNG receiving terminal; and a portion of the construction services. Under the terms of the EPCM agreement, Bechtel will be paid on a cost reimbursable basis, plus a fixed fee in the amount of $18.5 million. A discretionary bonus may be paid to Bechtel at Sabine Pass LNG’s sole discretion upon completion of Phase 2–Stage 1.

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EPC Tank Contract. Sabine Pass LNG entered into an EPC LNG tank contract with Zachry Construction Corporation (“Zachry”) and Diamond LNG LLC (“Diamond”) under which Zachry and Diamond will furnish all plant, labor, materials, tools, supplies, equipment, transportation, supervision, technical, professional and other services, and perform all operations necessary and required to satisfactorily engineer, procure materials for and construct the two Phase 2–Stage 1 LNG storage tanks. The tank contract provides that Zachry and Diamond will receive a lump-sum, total fixed price payment for the two Phase 2–Stage 1 tanks of approximately $140.9 million, which is subject to adjustment based on fluctuations in the cost of labor and certain materials, including the steel used in the Phase 2–Stage 1 tanks, and change orders.

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EPC LNG Unit Rate Soil Contract. Sabine Pass LNG entered into an EPC LNG unit rate soil contract with Remedial Construction Services, L.P. (“Recon”). Under the soil contract, Recon is required to furnish all plant, labor, materials, tools, supplies, equipment, transportation, supervision, technical, professional and other services, and perform all operations necessary and required to satisfactorily conduct soil remediation and improvement on the Phase 2 site, unless otherwise set forth in the soil contract. The soil contract price is based on unit rates. Payments under the soil contract are based on quantities of work performed at unit rates.

Corpus Christi LNG

We currently estimate that the cost of constructing the Corpus Christi LNG receiving terminal will be approximately $650 million to $750 million, before financing costs. This estimate is preliminary and is subject to change. We will contemplate making a final investment decision to complete construction of the Corpus Christi LNG receiving terminal upon, among other things, achieving acceptable commercial arrangements and entering into acceptable financing arrangements.

In order to accelerate the timing of its development of the Corpus Christ LNG receiving terminal, Corpus Christi LNG elected in April 2006 to commence preliminary site work and entered into an engineering, procurement and construction services agreement for such preliminary work which has since been completed.

Creole Trail LNG

We currently estimate that the cost of constructing the Creole Trail LNG receiving terminal will be approximately $850 million to $950 million, before financing costs. Our cost estimate is preliminary and is subject to change. We will contemplate making a final investment decision to commence construction of the Creole Trail LNG receiving terminal upon, among other things, achieving acceptable commercial arrangements and entering into acceptable financing arrangements.

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 with capital contributions by the limited partners. We did not receive any capital calls, and made no capital contributions, in the first quarter of 2007. In view of the closing of a $383 million private placement of notes in December 2005 by Freeport LNG, we do not

anticipate any capital calls in the foreseeable future. However, in the event of any 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 any future 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 our equity or debt securities.

Our Proposed Pipelines

We currently expect to fund the costs of our pipeline projects approved by our board of directors from our existing cash balances.

Sabine Pass Pipeline

We estimate the total cost to construct the Sabine Pass Pipeline to be approximately $100 million. This cost includes work included in the EPC pipeline contract discussed below and costs related to interconnection with third-party pipelines and to right-of-ways. We have sufficient funds to construct the Sabine Pass Pipeline. As of March 31, 2007, we had paid $34.3 million of Sabine Pass Pipeline construction costs.

In February 2006, Cheniere Sabine Pass Pipeline, L.P., our wholly-owned subsidiary, entered into an EPC pipeline contract with Willbros Engineers, Inc. (“Willbros”). Under the EPC pipeline contract, Willbros will provide Cheniere Sabine Pass Pipeline, L.P. with services for the management, engineering, material procurement, construction and construction management of the Sabine Pass Pipeline. Cheniere Sabine Pass Pipeline, L.P. 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.

Creole Trail Pipeline

We estimate the total cost to construct Phase 1 of the Creole Trail Pipeline to be approximately $400 million to $450 million. Our cost estimate is subject to change due to such items as cost overruns, change orders, delays in construction, increased component and material costs and escalation of labor costs. As of March 31, 2007, we had paid $76.1 million of construction costs for Phase 1 of the Creole Trail Pipeline.

Phase 1 of the Creole Trail Pipeline consists of approximately 78 miles of natural gas pipeline interconnecting with the Sabine Pass Pipeline, running east to the site of the Creole Trail LNG receiving terminal and then north and northeast along a corridor that will allow for interconnection points with existing interstate and intrastate natural gas pipelines in southwest Louisiana.

Cheniere Creole Trail Pipeline, L.P. (“CCTP”), our wholly-owned subsidiary, has issued purchase orders to ILVA S.p.A. and CPW America Co. for the purchase of all of the pipe needed to construct Phase 1 of the Creole Trail Pipeline. In the first quarter of 2007, CCTP entered into construction agreements with Sunland Construction, Inc. and Sheehan Pipe Line Construction Company to construct Phase 1 of the Creole Trail Pipeline. We anticipate that construction of Phase 1 of the Creole Trail Pipeline will commence in the second quarter of 2007 and that Phase 1 operations will commence in the second quarter of 2008.

Corpus Christi Pipeline

Construction contracts for the Corpus Christi Pipeline 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. We have committed $40 million initially to our marketing and trading activities, in addition to overhead costs and storage charges. We expect that our committed amount will increase as our LNG and natural gas marketing business develops.

PPM Agreement

In April 2006, Cheniere Marketing entered into a 10-year Gas Purchase and Sale Agreement with PPM Energy, Inc. (“PPM”). Subject to completion of certain of our LNG receiving terminals and pipelines, the agreement provides 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 requires Cheniere Marketing to allocate to PPM a portion of the LNG that it procures under certain planned long-term LNG supply agreements.

GDF Agreement

In April 2007, Cheniere Marketing and Gaz de France International Trading S.A.S. (“GDF”), a wholly-owned subsidiary of Gaz de France, executed a Master Ex-Ship LNG Sales Agreement (“Master Agreement”) and related option agreements. The Master Agreement governs the transactions between the parties in the purchase and sale of LNG, but neither party has an obligation under the Master Agreement until both parties have entered into a written order containing the specific quantity, purchase price and other terms of the purchase and sale of the LNG. GDF and Cheniere Marketing entered into a specific order under the Master Agreement providing for the purchase by Cheniere Marketing of up to seven (7) LNG cargoes on an ex-ship basis from GDF for the period from April through October 2008. The purchase price for such cargoes will be 94% of the final New York Mercantile exchange (“NYMEX”) settlement price per million British thermal unit (“MMBtu”) for a specified month, less $0.65 per MMBtu.

In April 2007, Cheniere Marketing and GDF also entered into the GDF Transatlantic Option Agreement (“GDF Option Agreement”) and the Cheniere Transatlantic Option Agreement (“Cheniere Option Agreement”), both of which are to be governed by the terms of the Master Agreement. Under the GDF Option Agreement, Cheniere Marketing granted GDF the option to sell one (1) cargo of LNG per month to Cheniere Marketing, exercisable each month during the Option Period, which is the period beginning on the first day of the month following the later to occur of (i) the commercial start up of the first expansion of the Isle of Grain LNG regasification terminal located in Kent, England and (ii) the commercial start up of the Sabine Pass LNG regasification terminal, continuing through the fifteenth (15th) anniversary of such date. Under the Cheniere Option Agreement, GDF has granted Cheniere Marketing the option to sell one (1) cargo of LNG per month to GDF, exercisable each month during the Option Period.

The effectiveness of the above transactions remain subject to satisfaction of certain conditions, including the approval on or prior to July 1, 2007 of the board of directors of each of the parties, the board of directors of their respective parent companies, or the relevant management committees of a party or its parent company.

Cheniere Energy Partners, L.P. Initial Public Offering

On March 26, 2007, Cheniere Partners and Holdings completed a public offering of a total of 13,500,000 Cheniere Partners’ common units (the “Offering”). Cheniere Partners received $98.4 million of net proceeds upon issuance of 5,054,164 common units to the public in the Offering and Holdings received $164.5 million of net proceeds in connection with its sale of 8,445,836 common units of Cheniere Partners. In April 2007, the

underwriters of the Offering exercised their over-allotment option with Holdings for the sale of an additional 2,025,000 common units. Holdings received $39.4 million of net proceeds from such sale. The $203.9 million net proceeds received by Holdings is unrestricted as to its use by us while the $98.4 million received by Cheniere Partners is restricted and is invested in U.S. treasury securities to fund a distribution reserve. As a result of the transactions described above, our combined general partner and limited partner ownership interest in Cheniere Partners was reduced to approximately 90.6%.

For each calendar quarter through June 30, 2009, Cheniere Partners will make initial quarterly cash distributions of $0.425 per unit on all outstanding common units, as well as related distributions to the general partner, using cash and earned interest from the distribution reserve that was funded with the $98.4 million of net proceeds that it received from the Offering. During this period, based on our current holdings of approximately 41% of the common units and 100% of the general partner units, we will receive $4.8 million per quarter out of the total $11.4 million quarterly distribution. After June 30, 2009, the distribution reserve is expected to have been depleted, and Cheniere Partners will have to rely on the receipt of operating revenues from its various TUAs to fund future quarterly cash distributions to us and other unitholders.

In addition to the 10,891,357 common units held by Holdings (subsequent to the underwriters’ exercise of their over-allotment option), Holdings holds 135,383,831 subordinated units of Cheniere Partners. Combined, Holdings’ common and subordinated units represent an 88.6% ownership interest in Cheniere Partners. During the subordination period, however, the subordinated units will not be entitled to receive any distributions until the common units have received the initial quarterly distributions plus any arrearages on the initial quarterly distribution from prior quarters. The subordinated units do not accrue arrearages. The subordination period generally will end if:

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In addition to the 3,302,045 general partner units, representing a 2% ownership interest, held by the general partner of Cheniere Partners, a wholly-owned subsidiary of Holdings, the general partner also owns general partner incentive distribution rights, which will entitle it to increasing percentages of the cash that Cheniere Partners distributes in excess of $0.489 per unit per quarter.

Debt Agreements

Sabine Pass LNG Senior Secured Notes

In November 2006, Sabine Pass LNG consummated a private offering of an aggregate principal amount of $2,032 million of Sabine Pass LNG notes, consisting of $550 million of 7 1/4% Senior Secured Notes due 2013 and $1,482 million of 7 1/2% Senior Secured Notes due 2016. Sabine Pass LNG has filed a registration statement with the SEC offering to exchange the unregistered Sabine Pass LNG notes for a like amount of senior secured notes of Sabine Pass LNG which are registered under the Securities Act.

Interest on the Sabine Pass LNG notes is payable semi-annually in arrears on May 30 and November 30 of each year, beginning May 30, 2007. The Sabine Pass LNG notes are secured on a first-priority basis by a security interest in all of its equity interests and substantially all of its operating assets.

Pass LNG apply its net operating cash flow (i) first, to fund with monthly deposits its next semiannual payment of approximately $75.5 million of interest on the Sabine Pass LNG notes, and (ii) second, to fund a one-time, permanent debt service reserve fund equal to one semiannual interest payment of approximately $75.5 million on the Sabine Pass LNG notes. Distributions will be permitted only after Phase 1 target completion, as defined in the indenture governing the Sabine Pass LNG notes, or such earlier date as project revenues are received, upon satisfaction of the foregoing funding requirements, after satisfying a fixed charge coverage ratio test of 2:1 and after satisfying other conditions specified in the indenture.

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 at any time into our common stock under certain circumstances at an initial conversion rate of 28.2326 per $1,000 principal amount of the notes, which is equal to a conversion price of approximately $35.42 per share. We may redeem some or all of the notes on or before August 1, 2012, for cash equal to 100% of the principal plus any accrued and unpaid interest if in the previous 10 trading days the volume-weighted average price of our common stock exceeds $53.13, subject to adjustment, for at least five consecutive trading days. In the event of such 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.

Concurrently with the issuance of the Convertible Senior Unsecured Notes, we also entered into hedge transactions in the form of an issuer call spread (consisting of a purchase and a sale of call options on our common stock) with an affiliate of the initial purchaser of the notes, having a term of two years and a net cost to us of $75.7 million. These hedge transactions are expected to offset potential dilution from conversion of the notes up to a market price of $70.00 per share. The net cost of the hedge transactions was recorded as a reduction to Additional Paid-in-Capital in accordance with the guidance of 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 $239.8 million, after deducting the cost of the hedge transactions, the underwriting discount and related fees. As of March 31, 2007, no holders had elected to convert their notes.

Short-Term Liquidity Needs

We anticipate funding our more immediate liquidity requirements, including expenditures related to the construction of our LNG receiving terminals and pipelines, 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:

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cash balances;

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

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LNG receiving terminal capacity reservation fees; and

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collection of receivables.

Historical Cash Flows

The following table summarizes the changes in our cash and cash equivalents for the three months ended March 31, 2007 and 2006. Additional discussion of the key elements contributing to the changes between periods follows the table (in thousands).


	Three Months Ended March 31,
	2007			2006
Cash provided by (used in):
Operating activities	$	(28,456	)	$	(20,478	)
Investing activities		(113,898	)		(59,770	)
Financing activities		263,011			65,754

Net increase (decrease) in cash and cash equivalents	$	120,657		$	(14,494	)

Cash and cash equivalents at end of period	$	583,620		$	678,098

Operating Activities—Net cash used in operations increased to $28.5 million during the three months ended March 31, 2007 compared to $20.5 million during the three months ended March 31, 2006. This $8.0 million increase was primarily due to continued development of our LNG receiving terminals, pipelines, and marketing and trading businesses and increased costs to support such activities.

Investing Activities—Net cash used in investing activities was $113.9 million during the three months ended March 31, 2007 compared to $59.8 million during the three months ended March 31, 2006. During the first three months of 2007, we invested $160.7 million in constructing our LNG receiving terminals and pipelines, $98.4 million in Restricted Treasury Securities, $6.9 million in advances to contractors and $6.2 million in fixed assets. These investment activities were offset by a $157.2 million use of our restricted cash investments during the first three months of 2007 related to funding of our terminal construction activities discussed above. During the first three months of 2006, we invested $73.8 million relating to Phase 1 construction activities at our Sabine Pass LNG receiving terminal, $1.7 million in fixed assets and $2.0 million in 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 three months of 2006 related to funding of our Sabine Pass LNG receiving terminal construction activities discussed above and to make payments of interest and principal relating to the Holdings’ term loan outstanding at that time.

Financing Activities—Net cash provided by financing activities was $263.0 million during the three months ended March 31, 2007 compared to $65.8 million during the three months period ended March 31, 2006. During the first three months of 2007, we received $164.5 million in net proceeds from the sale of common units in Cheniere Partners and $98.4 million in net proceeds from the issuance of Cheniere Partners common units to minority owners. See Note 2—“Initial Public Offering of Cheniere Energy Partners, L.P. and Minority Interest” of our Notes to Consolidated Financial Statements for further discussion. During the first three months of 2006, we received proceeds from borrowings under the Sabine Pass LNG 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 Holdings’ term loan principal payment and $3.0 million in debt issuance costs related to the Sabine Pass credit facility, which became due upon the first borrowing under the facility.

Issuances of Common Stock

During the first three months of 2007, a total of 95,996 shares of our common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of $0.8 million. In addition, 162,248 shares of common stock were issued in satisfaction of cashless exercises of options to purchase 168,666 shares of common stock.

In January 2007, 628,396 shares of our common stock were issued to our employees and executive officers in the form of non-vested (restricted) stock awards related to our performance in 2006. During the first three months of 2007, we issued an additional 51,564 shares of non-vested restricted stock to new and existing employees.

Off-Balance Sheet Arrangements

As of March 31, 2007, 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

Three Months Ended March 31, 2007

vs. Three Months Ended March 31, 2006

Consolidated Results (in thousands):


	Three Months Ended March 31, 2007
	LNG Receiving Terminal			Natural Gas Pipeline			LNG & Natural Gas Marketing			Oil & Gas Exploration & Development			Corporate & Other			Consolidated
Revenue	$	—		$	—		$	(2,088	)	$	832		$	—		$	(1,256	)

Operating costs and expenses
LNG receiving terminal and pipeline development expenses		5,298			456			—			—			—			5,754
Exploration costs		—			—			—			359			—			359
Oil and gas production costs		—			—			—			67			—			67
Depreciation, depletion and amortization		45			—			103			90			837			1,075
General and administrative expenses		1,231			72			3,765			(16	)		16,209			21,261

Total operating costs and expenses		6,574			528			3,868			500			17,046			28,516

Income (loss) from operations		(6,574	)		(528	)		(5,956	)		332			(17,046	)		(29,772	)
Interest expense		(23,393	)		(211	)		—			—			(2,822	)		(26,426	)
Interest income		14,845			—			498			3			6,236			21,582

Income (loss) before income taxes and minority interest		(15,122	)		(739	)		(5,458	)		335			(13,632	)		(34,616	)
Minority interest		60			—			—			—			—			60

Net income (loss)	$	(15,062	)	$	(739	)	$	(5,458	)	$	335		$	(13,632	)	$	(34,556	)


	Three Months Ended March 31, 2006
	LNG Receiving Terminal			Natural Gas Pipeline			LNG & Natural Gas Marketing			Oil & Gas Exploration & Development			Corporate & Other			Consolidated
Revenue	$	—		$	—		$	—		$	422		$	—		$	422

Operating costs and expenses
LNG receiving terminal and pipeline development expenses		6,644			1,669			—			—			—			8,313
Exploration costs		—			—			—			838			—			838
Oil and gas production costs		—			—			—			51			—			51
Depreciation, depletion and amortization		30			—			—			59			517			606
General and administrative expenses		2,166			—			1,235			452			9,328			13,181

Total operating costs and expenses		8,840			1,669			1,235			1,400			9,845			22,989

Loss from operations		(8,840	)		(1,669	)		(1,235	)		(978	)		(9,845	)		(22,567	)
Derivative gain		761			—			—			—			—			761
Interest expense		(6,466	)		—			—			—			(4,672	)		(11,138	)
Interest income		1,881			—			—			—			7,663			9,544
Other income		—			—			—			176			—			176

Loss before income taxes		(12,664	)		(1,669	)		(1,235	)		(802	)		(6,854	)		(23,224	)
Income tax benefit		—			—			—			—			7,413			7,413

Net income (loss)	$	(12,664	)	$	(1,669	)	$	(1,235	)	$	(802	)	$	559		$	(15,811	)

Financial results for the first quarter of 2007 reflect a net loss of $34.6 million, or $0.63 per share (basic and diluted), compared to a net loss of $15.8 million, or $0.29 per share (basic and diluted), for the first quarter of 2006.

The major factors contributing to our net loss of $34.6 million during the first quarter of 2007 were LNG terminal and pipeline development expenses of $5.8 million, general and administrative expenses of $21.3 million and interest expense of $26.4 million. These expenses were partially offset by interest income of $21.6 million. 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 expenses 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.

LNG Receiving Terminal Segment

Financial results for our LNG receiving terminal segment for the first quarter of 2007 reflect a net loss of $15.1 million, compared to a net loss of $12.7 million for the first quarter of 2006.

LNG receiving terminal development expenses were 19.7% lower in the first quarter of 2007 with expenses of $5.3 million compared to the first quarter 2006 expenses of $6.6 million. Our development expenses include professional costs associated with front-end engineering and design work, obtaining orders from the FERC authorizing construction of our facilities and other required permitting for our planned LNG receiving terminals. In addition, development expenses include other costs related to employees directly involved in our development activities and land site rentals.

LNG receiving terminal development expenses were mainly attributable to our Creole Trail and Corpus Christi LNG receiving terminal projects and Phase 2—Stage 1 of the Sabine Pass LNG receiving terminal. In April 2006, we elected to commence preliminary site work at the site of our Corpus Christi LNG receiving terminal and, in July 2006, we commenced construction activities for Phase 2—Stage 1 of our Sabine Pass LNG receiving terminal. As a result, first quarter 2007 development expenses decreased by $3.0 million compared to the first quarter 2006. In the first quarter 2007, development expenses relating to our Creole Trail LNG receiving terminal also decreased by $1.0 million compared to the same period in 2006, as development activities for the project had been reduced. In addition, our LNG staff increased from an average of 45 employees in the first quarter of 2006 to an average of 89 employees in the first quarter of 2007 resulting in an increase in total compensation expense from $2.7 million in 2006 to $5.6 million in 2007.

General and administrative (“G&A”) expenses were 45.5% lower in the first quarter of 2007 with expenses of $1.2 million compared to expenses in the first quarter 2006 of $2.2 million. We incurred $0.4 million in Hurricane Rita relief efforts associated with our LNG terminals in the first quarter of 2006 that we did not occur in the first quarter of 2007. In addition, we incurred a $0.2 million reduction for capitalized labor associated with a terminal operations management system that is being implemented for our LNG receiving terminals in the first quarter of 2007, compared to expenses of $0.3 million in the first quarter of 2006.

The increase in interest income to $14.8 million in the first quarter of 2007 compared to $1.9 million in the first quarter of 2006 was due to an increase in average invested cash balances from the Sabine Pass LNG notes issued in November 2006. Similarly, the increase in interest expense, net of capitalization, from $23.4 million in the first quarter of 2007 to $6.5 million for the same period in 2006 was due to the issuance of the Sabine Pass LNG notes.

Natural Gas Pipeline Segment

Financial results for our natural gas pipeline segment for the first quarter of 2007 reflect a net loss of $0.7 million, compared to a net loss of $1.7 million for the first quarter of 2006.

Natural gas pipeline development expenses decreased to $0.5 million in the first quarter of 2007 compared to expenses of $1.7 million in the first quarter of 2006. In June 2006, we received approval from the FERC to construct and operate our Creole Trail Pipeline and a portion of our Sabine Pass Pipeline. In addition, we received approval in December 2006 to reduce our Creole Trail Pipeline capacity to a single pipeline. As a result, first quarter 2007 development expenses decreased $1.1 million when compared to the first quarter of 2006.

LNG and Natural Gas Marketing Segment

Financial results for our LNG and natural gas marketing segment for the first quarter of 2007 reflect a net loss of $5.5 million, compared to a net loss of $1.2 for the first quarter of 2006. We incurred a marketing and trading loss of $2.1 million in the first quarter of 2007 compared to zero in the first quarter of 2006. We commenced natural gas trading activities in December 2006.

G&A expenses increased to $3.8 million in the first quarter of 2007 compared to expenses of $1.2 million in the first quarter of 2006. G&A expenses in the first quarter of 2007 were primarily related to employee costs. Our marketing staff increased from an average of 6 employees in the first quarter of 2006 to an average of 34 employees in the first quarter of 2007, resulting in an increase in total compensation expense, including bonus accruals, of $3.1 million in the first quarter of 2007 to $0.7 million in the first quarter of 2006.

We earned $0.5 million in interest income in the first quarter of 2007 compared to zero in the first quarter of 2006 due to an increase in average invested cash balances as a result of our initial $40.0 million investment in our marketing and trading activities in November 2006.

Oil and Gas Exploration and Development Segment

Financial results for our oil and gas exploration and development segment for the first quarter of 2007 reflect net income of $0.3 million, compared to a net loss of $0.8 million for the first quarter of 2006. The increase in net income is primarily due to a decrease in exploration costs and an increase in production volumes from the addition of successful wells in 2006.

Corporate and Other

Financial results for corporate and other activities for the first quarter of 2007 reflect a net loss of $13.6 million, compared to a net income of $0.6 million for the first quarter of 2006.

G&A expenses increased 74.2% to $16.2 million in the first quarter of 2007 compared to $9.3 million in the first quarter of 2006. Our corporate staff increased from an average of 70 employees in the first quarter of 2006 to an average of 128 employees in the first quarter of 2007, resulting in total compensation, including bonus accruals, of $11.0 million in the first quarter of 2007 compared to $5.9 million in the first quarter of 2006. In addition, we incurred $1.4 million in legal fees associated with the Offering of Cheniere Partners in the first quarter of 2007.

Interest income decreased to $6.2 million in the first quarter of 2007 compared to $7.7 million in the first quarter of 2006 due to a decrease in average invested cash balances, primarily as a result of the termination of the Term Loan in November 2006.

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.

Interest expense was $2.8 million in the first quarter of 2007 compared to $4.7 million in the first quarter of 2006. The decrease was due to a reduction in the amount of outstanding indebtedness from the termination of the Term Loan in November 2006.

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 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 costs 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 have been expensed as required by the FASB Staff Position No. 13-1.

During the construction periods of our LNG receiving terminals, we capitalize interest and other related debt costs in accordance with Statement of Financial Accounting Standards (“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.

Regulated Operations

Our developing natural gas pipeline business is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and we have determined that certain of our pipeline systems to be constructed have met the criteria set forth in SFAS No. 71. Accordingly, we have applied the provisions of SFAS No. 71 to the affected pipeline subsidiaries beginning in the second quarter of 2006.

Our application of SFAS No. 71 is based on the current regulatory environment, our current projected tariff rates, and our ability to collect those rates. Future regulatory developments and rate cases could impact this accounting. Although discounting of our maximum tariff rates may occur, we believe the standards required by SFAS No. 71 for its application are met and the use of regulatory accounting under SFAS No. 71 best reflects the results of future operations in the economic environment in which we will operate. Regulatory accounting requires us to record assets and liabilities that result from the rate-making process that would not be recorded under GAAP for non-regulated entities. We will continue to evaluate the application of regulatory accounting principles based on on-going changes in the regulatory and economic environment. Items that may influence our assessment are:

•

inability to recover cost increases due to rate caps and rate case moratoriums;

•

inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;

•

excess capacity;

•

increased competition and discounting in the markets we serve; and

•

impacts of ongoing regulatory initiatives in the natural gas industry.

Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service.

Revenue Recognition

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

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 OCI, to the extent that the hedge is effective. We assess, both at the inception of each hedge and on an on-going basis, whether derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. On an on-going basis, we monitor the actual dollar offset of the hedges’ market values compared to hypothetical cash flow hedges. Any ineffective portion will be reflected in earnings. Ineffectiveness is the amount of gains or losses from derivative instruments that are not offset by corresponding and opposite gains or losses on the expected future transaction.

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. 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 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.

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, 2007 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 16—”Share-Based Compensation” of our Notes to Consolidated Financial Statements for a further discussion on share-based compensation.

New Accounting Pronouncements

In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN No. 48”), Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109. FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting

for Income Taxes. It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN No. 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN No. 48. The cumulative effect of applying the provisions of FIN No. 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. We adopted FIN No. 48 in the first quarter of 2007. The adoption of FIN No. 48 had no material impact on our financial position, results of operations or cash flows.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Oil and Gas Exploration Commodity Price Risk

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 exploration activities.

Marketing and Trading Commodity Price Risk

Through Cheniere Marketing, we conduct natural gas marketing and trading activities. We use value at risk (“VaR”) ad other methodologies for market risk measurement and control purposes. For the three months ended March 31, 2007, the one-day VaR with a 95% confidence interval of our marketing and trading positions averaged $0.5 million. At March 31, 2007, the one-day VaR of our marketing and trading positions was $0.3 million.

Cash Investments

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.

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 of 1934 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 are, and in the future may 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, 2007, there were no known threatened or pending legal matters that could reasonably be expected to have a material adverse 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 to commence 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, 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. We have not received any communication from the SEC with regard to this matter since September 2005.

Item 5.

Other Information

Through an indirect wholly-owned subsidiary, we previously held a minority interest in J & S Cheniere S.A. (“J & S Cheniere”), which was formed to engage in LNG transportation and trading through the utilization and management of LNG tankers, two of which are currently under construction and described in more detail below. The remaining majority interest in J & S Cheniere was held by Mercuria Energy Holding B.V. (“Mercuria”), a Netherlands corporation formerly known as J & S Energy Holding B.V. and affiliated with J & S Trading Company, Ltd., an international petroleum trading and marketing company. Our minority interest was initially held under an original shareholders agreement with Mercuria that was amended and restated on May 8, 2007 (“J & S amended shareholders agreement”). Pursuant to the J & S amended shareholders agreement, we increased our minority interest in J & S Cheniere to 49%. The remaining 51% of the shares of J & S Cheniere continues to be held by Mercuria.

In August 2004, J & S Cheniere executed a time charter agreement for an LNG tanker with a term of up to 10 years with Kawasaki Kisen Kaisha, Ltd. (“K-Line”) to charter a new build, 145,000 cubic meter-capacity LNG tanker being constructed by Kawasaki Shipbuilding Corporation. The LNG tanker is expected to be delivered in the fourth quarter of 2007. In August 2004, J & S Cheniere also executed a time charter agreement for an LNG tanker with a term of up to 10 years with a joint venture company established by K-Line, Shoei Kisen Kaisha, Ltd. and others to charter a new build, 154,200 cubic meter-capacity LNG tanker being constructed by Imabari Shipbuilding Co., Ltd. The LNG tanker is expected to be delivered in the second quarter of 2008.

Under the J & S amended shareholders agreement, the two shareholders have each committed to loan $25 million to J & S Cheniere for the purpose of collateralizing certain obligations of J & S Cheniere relating to the two K-Line LNG tanker time charters. Mercuria has also agreed to the cancellation of prior loans to J & S Cheniere. This agreement further provides for priority of distributions in that Mercuria is entitled to receive from J & S Cheniere the first $15.9 million of distributions, after which our subsidiary will be entitled to the next $10 million of distributions, and thereafter distributions will be made pro rata in accordance with the number of

shares owned by each shareholder. Each shareholder has the right to appoint half of the board of directors of J & S Cheniere. Either shareholder may propose a buy-out price to the other at any time, in which case the other shareholder must elect, in accordance with the J & S amended shareholders agreement, either to buy or sell at the proposed price. The selling shareholder would still be entitled to receive from J & S Cheniere any remaining unpaid portion of such shareholder’s respective $15.9 million or $10 million distribution entitlement. The J & S amended shareholders agreement also provides Mercuria the right to acquire all of our J & S Cheniere shares in the event that we experience a change in control (defined in the shareholders agreement to be a change in a majority of our board, the acquisition of more than 40% of our outstanding common stock other than as approved by our board of directors, or a merger or consolidation that results in 50% or less of the surviving entity’s voting securities being owned by the holders of our voting securities immediately prior to such transaction). The purchase price for such shares would equal the total contributions and loans made by us to J & S Cheniere plus any remaining unpaid portion of our $10 million distribution entitlement, and would be adjusted for our pro rata share of the undistributed amount of profits or losses incurred by J & S Cheniere.

In addition, the J & S amended shareholders agreement terminated a certain December 2003 option agreement that granted J & S Cheniere an option to enter into TUAs reserving up to 200 MMcf/d of capacity at each of the Sabine Pass LNG and Corpus Christi LNG receiving terminals. In replacement of such terminated option, Cheniere Marketing and J & S Cheniere agreed to continue negotiating LNG sale and purchase agreements that would provide for the sale by J & S Cheniere of approximately 78,475,000 MMBtus of stipulated maximum annual LNG reception quantity to Cheniere Marketing for delivery at each of the Sabine Pass LNG receiving terminal and the Corpus Christi LNG receiving terminal. The proposed form of these sale and purchase agreements is attached as an exhibit to the J & S amended shareholders agreement, although there is no binding obligation for the parties to enter into these agreements, and any definitive sale and purchase agreement that is entered into may involve substantially different terms. The form of sale and purchase agreement contemplates an initial five-year term, with up to three additional five-year renewal periods, at the option of J & S Cheniere, upon payment of a $1 million fee for each renewal. As contemplated in the form of sale and purchase agreement, J & S Cheniere would be able to “put” to Cheniere Marketing approximately 78,475,000 MMBtus of stipulated maximum annual LNG reception quantity with a minimum obligation to deliver one cargo per year (approximately 3,200,000 MMBtus of LNG), or pay an agreed amount if such cargo is not delivered, to the Sabine Pass LNG receiving terminal, at a price based on an agreed percentage of the price of natural gas at the NYMEX Henry Hub. It is contemplated that the same terms would apply in connection with the sale and purchase agreement between the parties for delivery of LNG reception quantity to the Corpus Christi LNG receiving terminal. The J & S amended shareholders agreement states that the sale and purchase agreements will contain a provision that, in the event of a sale by either shareholder of its entire interest in J & S Cheniere (other than because of a change of control of us), J & S Cheniere will automatically become obligated under each sale and purchase agreement to deliver, or pay agreed upon amounts if not delivered, to Cheniere Marketing an annual contract quantity equivalent to approximately 78,475,000 MMBtu of annual LNG reception quantity priced in accordance with the pricing provisions contained in such form of sale and purchase agreement.

The form of sale and purchase agreement also contemplates that, in the event that a sale and purchase agreement is terminated by J & S Cheniere because Cheniere Marketing fails to perform its purchase or payment obligations, or becomes bankrupt, or because a change of control of Cheniere has occurred, J & S Cheniere would enter into a TUA with Sabine Pass LNG or Corpus Christi LNG, as applicable, covering approximately 78,475,000 MMbtus of stipulated maximum annual LNG reception quantity for either of the Sabine Pass LNG receiving terminal or the Corpus Christi LNG receiving terminal, as applicable, if such terminal has commenced commercial operation. The form of this potential TUA, which we refer to as the J & S Cheniere contingent TUA, is attached to the form of sale and purchase agreement.

Sabine Pass LNG and Cheniere Marketing have entered into a related letter agreement in which Sabine Pass LNG has agreed to enter into the J & S Cheniere contingent TUA if and when applicable, and Cheniere Marketing has agreed to relinquish 78,475,000 MMBtus of stipulated maximum annual LNG reception quantity (and proportionately reduce its fixed monthly fee) under the Cheniere Marketing TUA if required to allow Sabine

Pass LNG to satisfy its obligations under the J & S Cheniere contingent TUA. This letter agreement cancels and supersedes the similar November 2006 letter agreement of Sabine Pass LNG and Cheniere Marketing that related to a potential TUA with J & S Cheniere under its now-terminated December 2003 option agreement.

Item 6.

Exhibits

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


10.1		Change Order 43 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.34 to Sabine Pass LNG, L.P.’s Registration Statement on Form S-4 (SEC file No. 333-138916), filed on April 3, 2007)

10.2		Master Ex-Ship LNG Sales Agreement, dated April 26, 2007, between Cheniere Marketing, Inc. and Gaz de France International Trading S.A.S., including Letter Agreement, dated April 26, 2007, and Specific Order No. 1, dated April 26, 2007

10.3		GDF Transatlantic Option Agreement, dated April 26, 2007, between Cheniere Marketing, Inc. and Gaz de France International Trading S.A.S.

10.4		Change Orders 44 and 45 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation

10.5		Summary of Compensation for Executive officers

10.6		Amended and Restated Shareholders Agreement, dated May 8, 2007, between Mercuria Energy Holding B.V. and Cheniere LNG Services, Inc.

10.7		Master Loan Agreement, dated May 8, 2007, between Cheniere LNG Services, Inc. and J & S Cheniere SA

10.8		Letter Agreement, dated May 8, 2007, between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P.

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

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

32.1		Certification 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 8, 2007