Edgar Filing: CHENIERE ENERGY INC

Form 10-Q for the Quarterly Period Ended September 30, 2007

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 September 30, 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 October 31, 2007, there were 47,494,577 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	1
	Consolidated Balance Sheets	1
	Consolidated Statements of Operations	2
	Consolidated Statement of Stockholders’ (Deficit) 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	23

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	43

Item 4.	Disclosure Controls and Procedures	43

Part II. OTHER INFORMATION

Item 1.	Legal Proceedings	44

Item 6.	Exhibits	44

PART I. FINANCIAL INFORMATION

Item 1.

Consolidated Financial Statements

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)


	September 30, 2007			December 31, 2006
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	446,579		$	462,963
Restricted cash and cash equivalents		234,546			176,827
Interest receivable		6,804			6,642
Accounts receivable		25,527			1,299
Derivative assets		3,048			—
Prepaid expenses and other		17,347			2,242

TOTAL CURRENT ASSETS		733,851			649,973
NON-CURRENT RESTRICTED CASH AND CASH EQUIVALENTS		620,938			1,071,722
NON-CURRENT RESTRICTED TREASURY SECURITIES		75,023			—
PROPERTY, PLANT AND EQUIPMENT, NET		1,399,345			748,818
DEBT ISSUANCE COSTS, NET		45,789			41,545
EQUITY METHOD INVESTMENTS		25,481			—
GOODWILL		76,844			76,844
INTANGIBLE ASSETS		6,073			4,331
ADVANCES UNDER LONG-TERM CONTRACTS		31,457			7,101
OTHER		2,133			4,154

TOTAL ASSETS	$	3,016,934		$	2,604,488

LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
CURRENT LIABILITIES
Accounts payable	$	7,755		$	3,659
Accrued liabilities		175,896			58,280
Derivative liabilities		881			—

TOTAL CURRENT LIABILITIES		184,532			61,939
LONG-TERM DEBT		2,757,000			2,357,000
DEFERRED REVENUE		41,000			41,000
OTHER NON-CURRENT LIABILITIES		7,359			1,302
MINORITY INTEREST		293,477			—
COMMITMENTS AND CONTINGENCIES		—			—
STOCKHOLDERS’ (DEFICIT) 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 September 30, 2007 and December 31, 2006
Issued and outstanding: 47,411,707 and 55,212,771 (excluding treasury shares), respectively		142			166
Treasury stock, 9,190,333 and no shares, respectively, at cost		(325,000	)		—
Additional paid-in-capital		434,755			390,256
Accumulated deficit		(376,270	)		(247,141	)
Accumulated other comprehensive loss		(61	)		(34	)

Total stockholders’ (deficit) equity		(266,434	)		143,247

Total liabilities and stockholders’ (deficit) equity	$	3,016,934		$	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 September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Revenues
Oil and gas sales	$	812		$	737		$	4,362		$	1,572
Marketing and trading loss		(418	)		—			(4,353	)		—

Total revenues		394			737			9			1,572

Operating costs and expenses
LNG receiving terminal and pipeline development expenses		10,071			2,923			26,357			6,730
Exploration costs		659			661			1,032			2,089
Oil and gas production costs		82			61			250			166
Impairment of fixed assets		—			1,628			18			1,628
Depreciation, depletion and amortization		1,952			896			4,523			2,080
General and administrative expenses		34,904			12,044			85,101			37,669

Total operating costs and expenses		47,668			18,213			117,281			50,362

Loss from operations		(47,274	)		(17,476	)		(117,272	)		(48,790	)
Loss from equity method investments		(191	)		—			(191	)		—
Derivative loss		—			(966	)		—			(44	)
Interest expense, net		(28,027	)		(10,886	)		(80,383	)		(33,120	)
Interest income		20,990			11,100			66,695			30,978
Other income (expense)		3			201			(181	)		485

Loss before income taxes and minority interest		(54,499	)		(18,027	)		(131,332	)		(50,491	)
Income tax provision		—			(15,079	)		—			(2,045	)

Loss before minority interest		(54,499	)		(33,106	)		(131,332	)		(52,536	)
Minority interest		1,045			—			2,203			—

Net loss	$	(53,454	)	$	(33,106	)	$	(129,129	)	$	(52,536	)

Net loss per common share—basic and diluted	$	(1.14	)	$	(0.61	)	$	(2.48	)	$	(0.97	)

Weighted average number of common shares outstanding—basic and diluted		46,728			54,496			51,974			54,361

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ (DEFICIT) EQUITY

(in thousands)

(unaudited)


	Common Stock					Treasury Stock					Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Stockholders’ (Deficit) Equity
	Shares		Amount			Shares		Amount			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Stockholders’ (Deficit) Equity
Balance—December 31, 2006	55,213		$	166		—		$	—		$	390,256		$	(247,141	)	$	(34	)	$	143,247
Issuances of stock	524			2		—			—			2,495			—			—			2,497
Issuances of restricted stock	872			2		—			—			(2	)		—			—			—
Forfeitures of restricted stock	(19	)		—		19			—			—			—			—			—
Stock-based compensation	—			—		—			—			42,040			—			—			42,040
Treasury stock acquired	(9,178	)		(28	)	9,178			(325,062	)		28			—			—			(325,062	)
Treasury stock retired	—			—		(7	)		62			(62	)		—			—			—
Other Comprehensive loss:
Foreign currency translation	—			—		—			—			—			—			(27	)		(27	)
Net loss	—			—		—			—			—			(129,129	)		—			(129,129	)

Balance—September 30, 2007	47,412		$	142		9,190		$	(325,000	)	$	434,755		$	(376,270	)	$	(61	)	$	(266,434	)

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)


	Nine Months Ended September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(129,129	)	$	(52,536	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		4,523			2,080
Impairment of unproved properties		783			416
Dry hole expense		—			894
Impairment of fixed assets		18			1,628
Amortization of debt issuance costs		4,460			2,752
Non-cash compensation		40,766			15,975
Use of restricted cash and cash equivalents		58,684			—
Restricted interest income on restricted cash and cash equivalents		(42,281	)		—
Deferred tax provision		—			2,045
Minority interest		(2,203	)		—
Non-cash derivative gain		—			(213	)
Other		(317	)		(257	)
Changes in operating assets and liabilities
Accounts receivable		(26,201	)		831
Interest receivable		(162	)		—
Prepaid expenses		(15,120	)		(380	)
Deferred rent		4,517			—
Regulatory assets		—			(12,343	)
Accounts payable and accrued liabilities		49,725			(1,673	)

NET CASH USED IN OPERATING ACTIVITIES		(51,937	)		(40,781	)

CASH FLOWS FROM INVESTING ACTIVITIES:
LNG terminal and pipeline construction-in-progress		(547,699	)		(307,559	)
Use (investment in) of restricted cash and cash equivalents		399,357			(62,336	)
Investments in restricted treasury securities		(98,442	)		—
Purchases of fixed assets		(21,275	)		(7,799	)
Investments in entities accounted for using the equity method		(25,025	)		—
Oil and gas additions, net of sales		20			(2,568	)
Advances under long-term contracts		(35,536	)		(11,762	)
Advance to EPC contractor		—			(2,729	)
Other		333			(6,652	)

NET CASH USED IN INVESTING ACTIVITIES		(328,267	)		(401,405	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuances of common units in partnership		203,946			—
Proceeds from issuance of common units to minority owners in partnership		98,442			—
Distributions to minority interest		(7,033	)		—
Proceeds from 2007 Term Loan		400,000			—
Payment of Holdings term loan		—			(4,500	)
Borrowings under Sabine Pass credit facility		—			351,500
Debt issuance costs		(9,711	)		(11,416	)
Sale of common stock		2,498			1,728
Purchase of treasury shares		(325,062	)		(931	)
Use of restricted cash and cash equivalents		740			—

NET CASH PROVIDED BY FINANCING ACTIVITIES		363,820			336,381

NET DECREASE IN CASH AND CASH EQUIVALENTS		(16,384	)		(105,805	)
CASH AND CASH EQUIVALENTS—BEGINNING OF PERIOD		462,963			692,592

CASH AND CASH EQUIVALENTS—END OF PERIOD	$	446,579		$	586,787

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, unless otherwise stated or indicated by context.

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.

NOTE 2—Initial Public Offering of Cheniere Energy Partners, L.P. and Associated 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 “Cheniere Partners 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 Cheniere Partners 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 initially 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 Cheniere Partners Offering.

Cheniere Partners used all of the net proceeds of $98.4 million it received from the sale of its common units 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 the quarterly distribution to be made in respect of the quarter ending June 30, 2009.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

On April 16, 2007, the underwriters of the Cheniere Partners Offering exercised their over-allotment option to purchase 2,025,000 additional common units, which resulted in net proceeds of approximately $39.4 million to Holdings as the selling unitholder.

The net proceeds of $164.5 million from the initial 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 Holdings are not assets of Cheniere Partners, and therefore are unrestricted as to our use and are available for corporate and general purposes.

As of September 30, 2007, our combined general partner and limited partner ownership interest in Cheniere Partners was approximately 90.6%. As of such date, we held 135,383,831 subordinated units, 10,891,357 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 distribution 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

•

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.

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 Cheniere Partners 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)		203,946
Distributions to minority interest		(7,033	)
Minority interest share of loss of Cheniere Partners		(2,203	)

Minority interest at September 30, 2007	$	293,152

(1)

Through the Cheniere Partners 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 Cheniere Partners Offering, Holdings sold a portion of the Cheniere Partners common units held by it to the public, realizing proceeds net of offering costs of $203.9 million, which

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

included $39.4 million of net proceeds realized once the underwriters exercised their option to purchase an additional 2,025,000 common units from Holdings. Due to the subordinated distribution rights on our subordinated units, 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—Treasury Stock

During the quarter ended September 30, 2007, we purchased 3.2 million shares of our common stock through the exercise of call options acquired in the issuer call spread purchased by us in connection with the issuance of the Convertible Senior Unsecured Notes (see Note 8—Long-Term Debt and Credit Facility). This purchase completed the acquisition of our common stock under the call option, bringing our total stock purchased to approximately 9.2 million shares with an aggregate purchase price of approximately $325.0 million. These shares were held as treasury stock at September 30, 2007.

NOTE 4—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 reduce the standby letter of credit to $4.1 million, which was the amount recorded as Current Restricted Cash and Cash Equivalents on our Consolidated Balance Sheet at September 30, 2007.

In November 2006, Sabine Pass LNG, L.P. (“Sabine Pass LNG”), our subsidiary now wholly-owned by Cheniere Partners, consummated a private offering of an aggregate principal amount of $2,032.0 million of Senior Secured Notes consisting of $550.0 million of 7.25% Senior Secured Notes due 2013 (the “2013 Notes”) and $1,482.0 million of 7.50% Senior Secured Notes due 2016 (the “2016 Notes” and collectively with the 2013 Notes, the “Sabine Pass LNG notes”) (see Note 8—Long-Term Debt and Credit Facility). Under the terms and conditions of the Sabine Pass LNG notes, we were required to fund cash reserve accounts for $335.0 million related to future interest payments through May 2009 and approximately $887.0 million to pay the remaining costs to complete the Sabine Pass LNG receiving terminal. These cash accounts are primarily controlled by a collateral trustee, and therefore are shown as Restricted Cash and Cash Equivalents on our Consolidated Balance Sheets. As of September 30, 2007 and December 31, 2006, $190.3 million and $176.3 million, respectively, of cash restricted for future interest payments due within one year and accrued construction costs have been classified as a current asset, and $608.0 million and $982.6 million, respectively, of cash restricted for remaining construction costs and future interest payments due beyond one year have been classified as a non-current asset on our Consolidated Balance Sheets.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

At the closing of the Cheniere Partners Offering discussed above in Note 2, Cheniere Partners funded a distribution reserve of $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 the distribution made in respect of the quarter ending 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. In May and August of 2007, we used the distribution reserve to pay cash distributions to unitholders. As of September 30, 2007, we classified the $75.0 million balance of U.S. treasury securities as Non-Current Restricted Treasury Securities on our Consolidated Balance Sheet, as these securities had original maturities greater than three months.

In September 2007, Cheniere Marketing, Inc. (“Cheniere Marketing”), a direct wholly-owned subsidiary of Cheniere, entered into a 364-day, $100.0 million revolving credit facility (the “Marketing Credit Facility”) (see Note 8—Long-Term Debt and Credit Facility). Under the terms and conditions of the Marketing Credit Facility, Cheniere Marketing is restricted until March 31, 2008 from declaring or paying any dividends or making any other distributions (by reduction of capital or otherwise) to any direct or indirect owner so long as the Marketing Credit Facility remains in effect or any amount is owed under the Marketing Credit Facility. Starting with the quarter ending March 31, 2008, Cheniere Marketing may pay dividends equivalent to its net income. As such, we have presented cash and cash equivalents held by Cheniere Marketing as Restricted Cash and Cash Equivalents. As of September 30, 2007, $39.7 million of cash restricted under the Marketing Credit Facility was classified as a current asset on our Consolidated Balance Sheet, as the Marketing Credit Facility will mature within one year.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

NOTE 5—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):


	September 30, 2007			December 31, 2006
LNG TERMINAL COSTS
LNG terminal construction-in-progress	$	1,044,577		$	684,008
LNG site and related costs, net		1,479			1,467

Total LNG terminal costs		1,046,056			685,475

NATURAL GAS PIPELINE COSTS
Pipeline construction-in-progress		309,698			45,615
Pipeline right-of-ways		12,872			2,134

Total natural gas pipeline costs		322,570			47,749

OIL AND GAS PROPERTIES, successful efforts
Proved		2,472			2,343
Unproved		—			779
Accumulated depreciation, depletion and amortization		(545	)		(263	)

Total oil and gas properties, net		1,927			2,859

FIXED ASSETS
Computers and office equipment		7,501			5,352
Furniture and fixtures		4,865			1,310
Computer software		10,869			8,043
Leasehold improvements		8,683			2,206
Machinery and equipment		452			—
Projects-in-progress		3,362			1,724
Other		392			123
Accumulated depreciation		(7,332	)		(6,023	)

Total fixed assets, net		28,792			12,735

PROPERTY, PLANT AND EQUIPMENT, NET	$	1,399,345		$	748,818

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.

Costs associated with the construction of the Sabine Pass LNG receiving terminal have been capitalized as construction-in-progress since the date the project satisfied our criteria for capitalization. For the nine months ended September 30, 2007 and 2006, we capitalized $46.1 million and $14.6 million of interest expense related to the construction of the Sabine Pass LNG receiving terminal. In March 2006, our Corpus Christi LNG receiving terminal satisfied the criteria for capitalization. Accordingly, costs associated with the initial site work for the

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Corpus Christi LNG receiving terminal have been capitalized as construction-in progress since that time. For the nine months ended September 30, 2007 and 2006, we capitalized $1.5 million and $0.2 million of interest expense related to this construction project, respectively.

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 third 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 nine months ended September 30, 2007 and 2006, we capitalized $8.4 million and $0.4 million of AFUDC to our natural gas pipeline projects, respectively.

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 $4.0 million for the nine months ended September 30, 2007.

NOTE 6—Investments in Unconsolidated Entities

Freeport LNG

We account for our 30% limited partner investment in Freeport LNG Development, L.P. (“Freeport LNG”) using the equity method of accounting. As of September 30, 2007 and December 31, 2006, we had unrecorded cumulative suspended losses of $17.8 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 and nine months ended September 30, 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 September 30, 2007 and December 31, 2006 and the results of Freeport LNG’s operations for the three and nine months ended September 30, 2007 and 2006 are summarized as follows (in thousands):


	September 30, 2007			December 31, 2006
Current assets	$	176,141		$	294,847
Construction-in-progress		804,462			594,191
Fixed assets, net, and other assets		9,547			9,684

Total assets	$	990,150		$	898,722

Current liabilities	$	18,314		$	38,621
Notes payable		1,031,123			903,369
Deferred revenue and other deferred credits		5,470			5,666
Partners’ capital		(64,757	)		(48,934	)

Total liabilities and partners’ capital	$	990,150		$	898,722


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Loss from continuing operations	$	(4,622	)	$	(5,659	)	$	(15,823	)	$	(24,054	)
Net loss		(4,622	)		(5,659	)		(15,823	)		(24,054	)
Cheniere’s 30% equity in net loss from limited partnership (1)		(1,387	)		(1,698	)		(4,747	)		(7,216	)

(1)	As discussed above, our equity in the net losses of Freeport LNG for the three- and nine-month periods ending September 30, 2007 and 2006, were suspended and included in our unrecorded cumulative suspended losses because our investment basis was zero.

J & S Cheniere

J & S Cheniere S.A. (“J & S Cheniere”), a Swiss corporation, was formed on December 23, 2003 to engage in LNG transportation and trading activities. On May 8, 2007, an Amended and Restated Shareholders Agreement (“J & S Cheniere Amended Agreement”) was executed for J & S Cheniere, by and between an indirect, wholly-owned subsidiary of Cheniere and Mercuria Energy Holding B.V. (“Mercuria”), a Netherlands corporation affiliated with Mercuria Energy Group Ltd., an international petroleum trading and marketing company. In connection with the execution of the J & S Cheniere Amended Agreement, we increased our ownership interest in J & S Cheniere to 49%. Mercuria holds the remaining 51% ownership interest. Each shareholder has the right to appoint half of the board of directors of J & S Cheniere.

Pursuant to the terms of the J & S Cheniere Amended Agreement, Cheniere and Mercuria have each loaned $25.0 million to J & S Cheniere for the purpose of collateralizing certain obligations of J & S Cheniere relating to two LNG tanker time charters. Mercuria also agreed to the cancellation of prior loans made by it to J & S Cheniere. Under the J & S Cheniere Amended Agreement, Mercuria is entitled to receive from J & S Cheniere the first $15.9 million of distributions, after which we will be entitled to the next $10.0 million of distributions. Thereafter, distributions will be made pro rata in accordance with the number of shares owned by each shareholder.

Prior to executing the J & S Cheniere Amended Agreement, we accounted for our investment in J & S Cheniere under the cost method of accounting. In connection with the execution of the J & S Cheniere Amended

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Agreement and the increase of our ownership interest to 49%, on May 8, 2007, we began accounting for our investment in J & S Cheniere under the equity method of accounting, which was applied on a retroactive basis and had no material effect on our overall consolidated financial position, results of operations or cash flows.

NOTE 7—Accrued Liabilities

As of September 30, 2007 and December 31, 2006, accrued liabilities consisted of the following (in thousands):


	September 30, 2007		December 31, 2006
LNG terminal construction costs	$	40,869	$	16,334
Accrued interest expense and related fees		61,703		24,861
Pipeline construction costs		37,076		7,039
Purchased physical gas		22,045		—
Payroll		10,249		5,512
Other accrued liabilities		3,954		4,534

Accrued liabilities	$	175,896	$	58,280

NOTE 8—Long-Term Debt and Credit Facility

As of September 30, 2007 and December 31, 2006, our long-term debt consisted of the following (in thousands):


	September 30, 2007		December 31, 2006
Sabine Pass LNG notes	$	2,032,000	$	2,032,000
2007 Term Loan		400,000		—
Convertible Senior Unsecured Notes		325,000		325,000

Total Long-Term Debt	$	2,757,000	$	2,357,000

Sabine Pass LNG Notes

In November 2006, Sabine Pass LNG consummated a private offering of an aggregate principal amount of $2,032.0 million of Sabine Pass LNG notes, consisting of $550.0 million of the 2013 Notes and $1,482.0 million of the 2016 Notes. In August 2007, Sabine Pass LNG concluded an exchange offer of its unregistered 2013 Notes and 2016 Notes for a like principal amount of notes registered under the Securities Act of 1933.

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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

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 $325.0 million aggregate principal amount of Convertible Senior Unsecured Notes due 2012 to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (“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 shares per $1,000 principal amount of the notes, which is equal to a conversion price of approximately $35.42 per share. As of September 30, 2007, no holders had elected to convert their notes.

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.

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 were entered into to offset potential dilution from conversion of the notes. 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 September 30, 2007, we had repurchased 9.2 million shares of our common stock through the exercise of the call options acquired in the issuer call spread purchased by us in connection with the issuance of the Convertible Senior Unsecured Notes at a cash price of $35.42 per share, for an aggregate purchase price of approximately $325.0 million.

2007 Term Loan

On May 31, 2007, Cheniere Subsidiary Holdings, LLC (“Cheniere Subsidiary”), a newly formed wholly-owned subsidiary of Cheniere, entered into a $400.0 million credit agreement (“2007 Term Loan”). Borrowings under the 2007 Term Loan generally bear interest at a fixed rate of 9.75% per annum. Interest is calculated on the unpaid principal amount of the 2007 Term Loan outstanding and is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year, beginning June 30, 2007. The 2007 Term Loan will mature on May 31, 2012. The net proceeds of $391.7 million from the 2007 Term Loan are being used for general corporate purposes, including our repurchase, completed during the quarter ended September 30, 2007, of approximately 9.2 million shares of our outstanding common stock pursuant to the exercise of the call options acquired in the issuer call spread purchased by us in connection with the issuance of the Convertible Senior Unsecured Notes.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Marketing Credit Facility

On September 14, 2007, Cheniere Marketing entered into the Marketing Credit Facility. In connection with the Marketing Credit Facility, a credit agreement, security agreement, collateral trust agreement and several related ancillary agreements were entered into by the parties. The Marketing Credit Facility provides up to $35.0 million of borrowings and up to $100.0 million of letters of credit, provided that the sum of the outstanding borrowings and the face amount of the outstanding letters of credit may not at any time exceed the lesser of $100.0 million and a borrowing base composed of cash or cash equivalents, receivables, broker margin deposits and inventory of Cheniere Marketing meeting certain criteria. Cheniere Marketing must use the letters of credit and the proceeds of loans only for financing, securing or guaranteeing the performance of its obligations related to the purchase, sale, storage, transfer or exchange of natural gas and other products, to support Cheniere Marketing’s obligations under commodity contracts and derivative contracts related to such products, and to fund the working capital requirements of Cheniere Marketing. Borrowings mature on the earlier of two months after such borrowings and September 12, 2008. The unpaid principal balance of each borrowing generally bears interest at a variable rate equal to LIBOR plus 1.50%. Interest is payable at the end of the relevant LIBOR interest period, which will be either one or two months. Cheniere Marketing may also elect to have borrowings bear interest at the prime rate of the lender or at the lender’s cost of funds plus 1.50%. As of September 30, 2007, we had no borrowings and $2.2 million letters of credit outstanding under the Marketing Credit Facility.

NOTE 9—Advances Under Long-Term Contracts

We have entered into certain engineering, procurement and construction (“EPC”) contracts and purchase agreements related to the construction of our Sabine Pass LNG receiving terminal that require us to make payments to fund costs that will be incurred or equipment that will be received in the future. Advances made under long-term contracts on purchase commitments are carried at face value and transferred to Property, Plant, and Equipment as the costs are incurred or equipment is received. As of September 30, 2007 and December 31, 2006, our Advances Under Long-term Contracts were $31.5 million and $7.1 million, respectively.

NOTE 10—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, Restricted Cash and Cash Equivalents, Derivative Assets and Liabilities, 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Financial Instruments (in thousands):


	September 30, 2007				December 31, 2006
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2013 Notes (1)	$	550,000	$	541,750	$	550,000	$	547,250
2016 Notes (1)		1,482,000		1,452,360		1,482,000		1,478,295
2007 Term Loan (2)		400,000		400,000		—		—
2.25% Convertible Senior Unsecured Notes due 2012 (3)		325,000		390,813		325,000		334,750
Restricted Treasury Securities (4)		75,023		77,279		—		—

(1)	The fair value of the Sabine Pass LNG notes is based on quotations obtained from broker-dealers who made markets in these and similar instruments as of September 28, 2007 and December 29, 2006.

(2)

The 2007 Term Loan bears interest at a fixed rate; therefore, the estimated fair value is expected to vary with changes in market interest rates. At September 30, 2007, the fair value of the debt instrument was stated at its carrying amount due to it being a non-trading instrument with no liquid market.

(3)	The fair value of our Convertible Senior Unsecured Notes is based on a closing trading price on September 28, 2007 and December 29, 2006.

(4)	The fair value of our Restricted Treasury Securities is based on quotations obtained from broker-dealers who made markets in these and similar instruments as of September 28, 2007.

NOTE 11—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 now an income 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 Statements of Operations for the nine months ended September 30, 2007 and 2006 included deferred income tax provision of zero and $2.0 million, respectively. The deferred income tax benefit recorded for the nine months ended September 30, 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, one of those specific circumstances existed, which related to a pre-tax accumulated other comprehensive loss of $12.3 million recorded as of September 30, 2006 in connection with our interest rate swaps. The deferred tax benefit for the nine months ended September 30, 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 September 30, 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 September 30,					Nine Months Ended September 30,
	2007		2006			2007		2006
Current income tax expense	$	—	$	—		$	—	$	—
Deferred income tax benefit		—		(15,079	)		—		(2,045	)

	$	—	$	(15,079	)	$	—	$	(2,045	)

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

We believe a 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 a first quarter tax gain resulting from the Cheniere Partners Offering.

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.

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. 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 tax audit of Cheniere and one of our wholly-owned subsidiaries for the two-year period ended December 31, 2003. We expect that all of our significant operating subsidiaries will be audited by the States of Texas and Louisiana for annual tax reporting periods ended on and after December 31, 2004. To date, all of the state-level income tax audits have been settled favorably and without changes. None of our foreign subsidiaries have been audited by any foreign taxing authorities and none have been notified by relevant taxing authorities of an impending audit.

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 our income tax provision.

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 September 30, 2007. We have determined that all of our material tax positions taken in our income tax returns meet, and the positions we expect to take in our future income tax filings will meet, the more-likely-than-not recognition threshold prescribed by FIN No. 48. We have $37.6 million of tax positions related to the accelerated recovery of certain capital costs for which the ultimate deductibility is highly certain, but for which there is some uncertainty related to the timing of the related current and future tax deductions. Under SFAS No. 109, the disallowance of an accelerated recovery period would not affect our annual reported effective tax rate but would most likely result in the acceleration of cash income tax payments to the relevant taxing authorities. Adjustments that would affect our current year taxable income would generally be offset by our available NOL carryovers, and therefore, no interest and penalties have been accrued with respect to this liability. We believe that it is reasonably possible that the amount of our unrecognized tax

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

benefits will decrease significantly within the next twelve months, but the amount of the decrease cannot be reasonably estimated at this time. To date, the adoption of FIN No. 48 has had no impact on our financial position, results of operations or cash flows.

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 adjusted.

NOTE 12—Net Loss Per Share

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

The following table reconciles basic and diluted weighted average common shares outstanding for the three and nine months ended September 30, 2007 and 2006 (in thousands except for loss per share):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Weighted average common shares outstanding:
Basic		46,728			54,496			51,974			54,361
Dilutive common stock options		—			—			—			—
Dilutive Convertible Senior Unsecured Notes		—			—			—			—

Diluted		46,728			54,496			51,974			54,361

Basic loss per share	$	(1.14	)	$	(0.61	)	$	(2.48	)	$	(0.97	)
Diluted loss per share	$	(1.14	)	$	(0.61	)	$	(2.48	)	$	(0.97	)

NOTE 13—Other Comprehensive Loss

The following table is a reconciliation of our net loss to our comprehensive loss for the three and nine months ended September 30, 2007 and 2006 (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Net loss	$	(53,454	)	$	(33,106	)	$	(129,129	)	$	(52,536	)
Other comprehensive loss items:
Cash flow hedges, net of income tax		—			(40,209	)		—			(16,004	)
Foreign currency translation		6			(13	)		(27	)		(47	)

Comprehensive loss	$	(53,448	)	$	(73,328	)	$	(129,156	)	$	(68,587	)

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

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

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


	Nine Months Ended September 30,
	2007		2006
Cash paid for interest, net of amounts capitalized	$	39,022	$	37,931
Construction-in-progress additions recorded as accrued liabilities	$	92,853	$	45,327

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 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 90.6% owned (at September 30, 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 natural gas pipelines to provide access to North American natural gas markets.

Through our LNG and natural gas marketing segment, 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 in the shallow waters of the Gulf of Mexico.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Revenues:
LNG receiving terminal	$	—		$	—		$	—		$	—
Natural gas pipeline		—			—			—			—
LNG and natural gas marketing		(418	)		—			(4,353	)		—
Oil and gas exploration and development		812			737			4,362			1,572

Total		394			737			9			1,572
Corporate and other (1)		—			—			—			—

Total consolidated	$	394		$	737		$	9		$	1,572

Net income (loss) from operations:
LNG receiving terminal	$	(10,876	)	$	(9,064	)	$	(39,323	)	$	(32,387	)
Natural gas pipeline		(2,045	)		667			(3,931	)		9,477
LNG and natural gas marketing		(6,473	)		(1,305	)		(18,382	)		(4,144	)
Oil and gas exploration and development		(399	)		(975	)		2,444			(3,352	)

Total		(19,793	)		(10,677	)		(59,192	)		(30,406	)
Corporate and other (1)		(33,661	)		(22,429	)		(69,937	)		(22,130	)

Total consolidated	$	(53,454	)	$	(33,106	)	$	(129,129	)	$	(52,536	)


	September 30, 2007		December 31, 2006
Total assets:
LNG receiving terminal	$	2,094,840	$	1,975,666
Natural gas pipeline		325,041		49,223
LNG and natural gas marketing		87,162		44,499
Oil and gas exploration and development		2,715		3,481

Total		2,509,758		2,072,869
Corporate and other (1)		507,176		531,619

Total consolidated	$	3,016,934	$	2,604,488

(1)	Includes corporate activities and certain intercompany eliminations.

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. 123R (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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

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 and nine months ended September 30, 2007, the total stock-based compensation expense (net of capitalization) recognized in our net loss was $22.7 million and $42.0 million, respectively. For the three and nine months ended September 30, 2007, the total stock-based compensation cost capitalized as part of the cost of capital assets was $0.6 million and $1.3 million, respectively.

For the three and nine months ended September 30, 2006, the total stock-based compensation expense (net of capitalization) recognized in our net loss was $5.1 million and $16.0 million, respectively. For the three and nine months ended September 30, 2006, the total stock-based compensation cost capitalized as part of the cost of capital assets was $0.5 million and $1.1 million, respectively.

The total unrecognized compensation cost at September 30, 2007 relating to non-vested share-based compensation arrangements granted under the 1997 Plan and 2003 Plan, before any capitalization, was $123.8 million. That cost is expected to be recognized over 4.5 years, with a weighted average period of 1.4 years.

SFAS No. 123R had no effect on our 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 $2.5 million and $1.7 million during the nine months ended September 30, 2007 and 2006, respectively.

Phantom Stock

In 2007, the Company established a 2007 Incentive Compensation Plan (“2007 Plan”) and a 2008-2010 Incentive Compensation Plan (“2008-2010 Plan”) covering executive officers and other key employees for the performance periods of 2007, 2008, 2009 and 2010. A total of 537,000 and 1,611,000 shares of phantom stock were granted under the 2007 and 2008-2010 Plans, respectively, which will be payable in shares of our common stock if stock price hurdles established by the plans are achieved. At its sole discretion, the Compensation Committee of our Board of Directors may elect to settle all or part of the phantom stock in cash. Using a Monte Carlo simulation, fair values of $18.4 million, $16.2 million, $13.4 million and $11.1 million were calculated for the performance periods 2007, 2008, 2009 and 2010, respectively. A projected earnings date was also forecasted on which the stock price hurdle will be achieved for the award related to each performance period. The fair value of the award for each performance period will be amortized as compensation expense ratably from the date of plan approval to the date it is expected to be earned. For the three and nine months ended September 30, 2007, totals of $12.2 million and $17.2 million, respectively, were recognized as compensation expense relating to these awards.

Stock Options

During the first nine months of 2007, we issued options to purchase 10,000 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 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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

granted in 2007 is based on the “simplified” method of estimating the 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.

The table below provides a summary of stock option activity under the combined plans as of September 30, 2007, and changes during the nine months then ended:


	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (years)	Aggregate Intrinsic Value
	(in thousands)					(in thousands)
Outstanding at January 1, 2007	5,187		$	34.25
Granted	10			33.18
Exercised	(549	)		6.07
Forfeited or Expired	(34	)		34.51

Outstanding at September 30, 2007	4,614		$	37.60	6.4	$	36,145

Exercisable at September 30, 2007	1,291		$	20.36	3.6	$	24,366

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. The adoption of this amendment did not have an impact on our assessment of stock options ultimately expected to vest, and, therefore, had no impact on our financial position, results of operations or cash flows.

Stock and Non-Vested Stock

We have granted stock and non-vested (restricted) stock to employees, executive officers, one consultant 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 compensation and an increase in additional paid-in-capital over the requisite service period.

In January 2007, 630,396 shares having three-year graded vesting were issued to our employees and executive officers in the form of non-vested stock awards related to our performance in 2006. In May 2007, 30,574 shares having a one-year graded vesting were issued to our directors. In the nine months ended September 30, 2007, a total of 242,755 shares of non-vested stock having four-year graded vesting were issued to new and existing employees.

On May 25, 2007, the Compensation Committee of our Board of Directors approved a bonus plan covering substantially all employees not otherwise included in the 2007 Plan. This plan provides covered employees the ability to earn bonuses based on the achievement of established annual performance goals as well as a stock price appreciation goal. For some employees, part of the bonus may be paid in restricted stock that has graded vesting in three equal amounts over a three-year period. A fair value of $11.0 million has been estimated for the

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

restricted stock expected to be granted in 2008 for the 2007 performance period. It has been calculated by analysis of the likelihood of plan goals being achieved, Monte Carlo simulation of our projected stock price appreciation, and the target bonus available to each covered employee. The fair value will be recalculated at each balance sheet date until the total number of restricted shares to be granted, if any, has been determined. Because of the existence of the stock price appreciation goal, which is a market condition, the restricted stock is not eligible for amortization under the straight-line method, and each vesting tranche is being amortized separately. For the three and nine months ended September 30, 2007, a total of $1.1 million and $1.6 million was recognized as compensation expense relating to the restricted stock currently forecasted to be awarded in 2008 for 2007 performance under the bonus plan, respectively.

The table below provides a summary of the status of our outstanding non-vested shares under the 2003 Plan as of September 30, 2007, and changes during the three months then ended (in thousands except for per share information). It does not include any shares forecasted to be granted in 2008.


	Non-Vested Shares		Weighted Average Grant-Date Fair Value Per Share
Non-vested at January 1, 2007	555		$	33.97
Granted	904			31.55
Vested	(94	)		34.36
Forfeited	(20	)		28.91

Non-vested at September 30, 2007	1,345		$	31.38

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, awards made by the Compensation Committee have been in the form of non-qualified stock options, restricted stock, bonus stock and phantom 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. The phantom stock will be payable in shares of the Company’s common stock subject to the common stock meeting or exceeding an established price hurdle during the last 20 trading days of a performance year. Any phantom stock not payable following December 31, 2010 will be forfeited.

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 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;

•

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;

•

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;

•

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

•

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;

•

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

•

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

•

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

These forward-looking statements are often identified by the use of terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this quarterly report.

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

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 terminals, natural gas pipelines, LNG and natural gas marketing, and oil and gas exploration and development.

LNG Receiving Terminals 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 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% limited partner interest in a fourth LNG receiving terminal 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 commercial operation during the second quarter of 2008 with initial send out capacity of 2.6 Bcf/d and storage capacity of 10.1 Bcf. We will contemplate making final investment decisions to complete construction of the Corpus Christi LNG receiving terminal and to commence construction of the Creole Trail LNG receiving terminal upon, among other things, achieving acceptable commercial arrangements and arranging appropriate financing.

Natural Gas Pipelines Business

We are developing natural gas pipelines to provide access to North American natural gas markets. In July 2007, we filed an application with the Federal Energy Regulatory Commission (“FERC”) to merge our Sabine Pass Pipeline into our Creole Trail Pipeline, thereby creating a 151-mile integrated pipeline system, which we refer to as the Creole Trail Pipeline. In October 2007, the FERC approved our application. Initial construction of the Creole Trail Pipeline (consisting of 94 miles of natural gas pipeline) commenced in the second quarter of 2007, and we anticipate that a portion of the pipeline will be available for operations in the fourth quarter of 2007, with the remaining portion anticipated to be available for operations beginning the second quarter of 2008.

LNG and Natural Gas Marketing Business

We intend to purchase LNG primarily 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.

Other LNG Interests

Through an indirect wholly-owned subsidiary, we hold 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. The majority interest in J & S Cheniere is held by one other shareholder, Mercuria Energy Holding B.V. (“Mercuria”), a Netherlands corporation affiliated with Mercuria Energy Group Ltd., an international petroleum trading and marketing company. On May 8, 2007, the agreement between the shareholders of J & S Cheniere was amended (“J & S Cheniere Amended Agreement”), and 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.

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 in the shallow waters of the Gulf of Mexico.

LIQUIDITY AND CAPITAL RESOURCES

General

We are primarily engaged in LNG-related business activities. Our three LNG receiving terminal projects, our proposed pipelines, and our LNG and natural gas marketing business will require significant amounts of capital and are subject to risks and delays.

We have obtained financing and approval of our board of directors to construct the Sabine Pass LNG receiving terminal and the Creole Trail Pipeline, as more fully described below. The estimated costs of these projects, before financing costs, are $1.4 billion to $1.5 billion for the Sabine Pass LNG receiving terminal and $500 million to $550 million for the Creole Trail Pipeline.

As of September 30, 2007, we had an unrestricted Cash and Cash Equivalents balance of $446.6 million. In addition, we had $930.5 million in Restricted Cash and Cash Equivalents and U.S. Treasury Securities, including $513.6 million for the remaining construction costs of the Sabine Pass LNG receiving terminal, $284.7 million for interest payments through May 2009 related to the Sabine Pass LNG notes described below, $86.7 million for cash distributions through the distribution made in respect of the quarter ending June 2009 to the common unitholders of Cheniere Partners and related distributions to its general partner and $40.7 million held in a wholly-owned subsidiary that is restricted by a loan agreement. As a result, we believe that we have adequate financial resources available to us to complete construction of the currently approved projects described above. Our LNG-related business activities are not expected to begin to operate and generate significant cash flows before the second quarter of 2008, at the earliest.

Our LNG Receiving Terminals

Sabine Pass LNG

Customer TUAs

Each of the customers at the Sabine Pass LNG receiving terminal must make the full contracted amount of capacity reservation fee payments under its TUA whether or not it uses any of its reserved capacity. Provided the Sabine Pass LNG receiving terminal has achieved commercial operation, which we expect will occur during the second quarter of 2008, these capacity reservation fee TUA payments will be made by the following customers:

•

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;

•

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

•

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 in 2008 commencing with commercial operations. 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 capacity reservation fees payable under its TUA.

Construction of Receiving Terminal

The Sabine Pass LNG receiving terminal is being constructed with regasification capacity of 4.0 Bcf/d and five LNG storage tanks with an aggregate LNG storage capacity of 16.8 billion cubic feet (“Bcf”). We estimate that the aggregate cost to complete construction 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”). As of September 30, 2007, we had incurred $941.9 million of construction costs, not including financing costs.

Corpus Christi LNG

In order to accelerate the timing of its development of the Corpus Christi 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. Engineering and design work on the LNG receiving terminal is ongoing. We contemplate making a 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.

Creole Trail LNG

We contemplate making a 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

Freeport LNG

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 nine months of 2007, nor do we anticipate any capital calls in the foreseeable future.

J & S Cheniere S.A.

Under the J & S Cheniere Amended Agreement, the two shareholders have each loaned $25 million to J & S Cheniere for the purpose of collateralizing certain obligations of J & S Cheniere relating to two LNG tanker time charters, and Mercuria has canceled prior loans to J & S Cheniere. This agreement 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 we will be entitled to the next $10.0 million of distributions. Thereafter, distributions will be made pro rata in accordance with the number of shares owned by each shareholder. The J & S Cheniere Amended 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. 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 $10.0 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.

Our Proposed Pipelines

We currently expect to fund the remaining costs of pipeline projects approved by our board of directors from existing cash balances. We estimate the total cost to construct the Creole Trail Pipeline to be approximately $500 million to $550 million. This estimate includes the costs to construct the pipeline and costs related to interconnections with third-party pipelines and to right-of-ways. We have sufficient funds to construct the pipeline. As of September 30, 2007, we had incurred $310.6 million of costs for the Creole Trail Pipeline.

Construction of the Corpus Christi Pipeline is contingent upon our decision to complete construction of the Corpus Christi LNG receiving terminal.

Our LNG and Natural Gas Marketing Business

We will need funds to develop our LNG and natural gas marketing business, including capital required to satisfy any creditworthiness requirements under contracts and 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 provide for these expenses with available cash balances. We have committed $60.0 million to our marketing and trading activities, in addition to funding overhead costs and capital expenditures. We expect that our committed amount will increase as our LNG and natural gas marketing business develops. In September 2007, we established the Marketing Credit Facility described below.

Cheniere Energy Partners, L.P.

On March 26, 2007, 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 “Cheniere Partners Offering”). Cheniere Partners received $98.4 million of net proceeds upon the issuance of 5,054,164 common units to the public in the Cheniere Partners 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 Cheniere Partners Offering exercised their over-allotment option with Holdings for the purchase 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 was unrestricted as to its use by us while the $98.4 million received by Cheniere Partners was restricted and is invested in U.S. Treasury Securities to fund a distribution reserve. As a result of these transactions, 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 quarterly cash distributions of $0.425 per unit on all outstanding common units, as well as related distributions to its 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 Cheniere Partners Offering. From the date of the Cheniere Partners Offering through June 30, 2009, based on our current holdings of approximately 41% of the common units (10,891,357 common units) and 100% of the general partner units (3,302,045 general partner units), we anticipate receiving $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 rely on the receipt of operating revenues from Sabine Pass LNG’s various TUAs to fund future quarterly cash distributions to us and other unitholders.

In addition to 10,891,357 common units, Holdings, through a wholly-owned subsidiary, also holds 100% of the subordinated units of Cheniere Partners (135,383,831) . Holdings’ common, general partner and subordinated units represent an aggregate 90.6% 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:

•

if Cheniere Partners has earned and paid at least $0.638 (150.0% 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.

In addition to the 3,302,045 general partner units, representing a 2.0% ownership interest, held by the general partner of Cheniere Partners, a wholly-owned subsidiary of Holdings, the general partner also owns incentive distribution rights, which entitle it to increasing percentages (up to a maximum of 50.0%) 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 $2,032.0 million of Sabine Pass LNG notes, consisting of $550.0 million of 7.25% Senior Secured Notes due 2013 and $1,482.0 million of 7.50% Senior Secured Notes due 2016. In August 2007, Sabine Pass LNG concluded an exchange offer of its unregistered 2013 Notes and 2016 Notes for a like principal amount of notes registered under the Securities Act of 1933.

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 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 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. As of September 30, 2007, no holders had elected to convert their notes.

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.

2007 Term Loan

On May 31, 2007, Cheniere Subsidiary Holdings, LLC (“Cheniere Subsidiary”), a newly formed wholly-owned subsidiary of Cheniere, entered into a $400.0 million credit agreement (“2007 Term Loan”). Borrowings under the 2007 Term Loan generally bear interest at a fixed rate of 9.75% per annum. Interest is calculated on the unpaid principal amount of the 2007 Term Loan outstanding and is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year, commencing June 30, 2007. The 2007 Term Loan will mature on May 31, 2012. The net proceeds from the 2007 Term Loan were $391.7 million and are being used for general corporate purposes, including the repurchase, completed in July 2007, of approximately 9.2 million

shares of our outstanding common stock pursuant to the exercise of the call options acquired in the issuer call spread purchased by us in connection with the issuance of the Convertible Senior Unsecured Notes.

Marketing Credit Facility

On September 14, 2007, Cheniere Marketing entered into the Marketing Credit Facility. In connection with the Marketing Credit Facility, a credit agreement, security agreement, collateral trust agreement and several related ancillary agreements were entered into by the parties. The Marketing Credit Facility provides up to $35.0 million of borrowings and up to $100.0 million of letters of credit, provided that the sum of the outstanding borrowings and the face amount of the outstanding letters of credit may not at any time exceed the lesser of $100.0 million and a borrowing base composed of cash or cash equivalents, receivables, broker margin deposits and inventory of Cheniere Marketing meeting certain criteria. Cheniere Marketing must use the letters of credit and the proceeds of loans only for financing, securing or guaranteeing the performance of its obligations related to the purchase, sale, storage, transfer or exchange of natural gas and other products, to support Cheniere Marketing’s obligations under commodity contracts and derivative contracts related to such products, and to fund the working capital requirements of Cheniere Marketing. Borrowings mature on the earlier of two months after such borrowings and September 12, 2008. The unpaid principal balance of each borrowing generally bears interest at a variable rate equal to LIBOR plus 1.50%. Interest is payable at the end of the relevant LIBOR interest period, which will be either one or two months. Cheniere Marketing may also elect to have borrowings bear interest at the prime rate of the the lender or at the lender’s cost of funds plus 1.50%. As of September 30, 2007, we had no borrowings and $2.2 million of letters of credit outstanding under the Marketing Credit Facility.

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 LNG and natural gas marketing business, and our oil and gas exploration, development and exploitation activities, through a combination of any or all of the following:

•

cash balances;

•

borrowings under our existing credit facilities and/or the establishment of additional credit facilities;

•

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

•

sales of units of Cheniere Partners;

•

LNG receiving terminal capacity reservation fees; and

•

collection of receivables.

Historical Cash Flows

The following table summarizes the changes in our cash and cash equivalents for the nine months ended September 30, 2007 and 2006 (in thousands). Additional discussion of the key elements contributing to the changes between periods follows the table.


	Nine Months Ended September 30,
	2007			2006
Cash provided by (used in):
Operating activities	$	(51,937	)	$	(40,781	)
Investing activities		(328,267	)		(401,405	)
Financing activities		363,820			336,381

Net increase (decrease) in cash and cash equivalents	$	(16,384	)	$	(105,805	)

Cash and cash equivalents at end of period	$	446,579		$	586,787

Operating Activities—Net cash used in operations increased to $51.9 million during the nine months ended September 30, 2007 compared to $40.8 million during the nine months ended September 30, 2006. This $11.1 million increase was primarily due to continued development of our LNG receiving terminals and related pipelines and increased costs to support such activities that were partially offset by utilization of restricted cash and cash equivalents to fund our operations during the first nine months of 2007 compared to the same period in 2006.

Investing Activities—Net cash used in investing activities was $328.3 million during the nine months ended September 30, 2007 compared to $401.4 million during the nine months ended September 30, 2006. During the first nine months of 2007, we invested $547.7 million in constructing our LNG receiving terminals and pipelines, $98.4 million in restricted treasury securities, $25.0 million in an investment accounted for using the equity method, $35.5 million in advances to contractors and $21.3 million in fixed assets. These investment activities were offset by a $399.4 million use of our restricted cash investments during the first nine months of 2007 related to the funding of our LNG receiving terminal construction activities discussed above. During the first nine months of 2006, we invested $307.6 million relating to our LNG receiving terminal and pipeline construction activities and we increased our investment in restricted cash and cash equivalents by $62.3 million ($87.9 million to secure a letter of credit, and net of debt payments for interest and principal). In the first nine months of 2006, our cash used in investing activities was higher because we also made advances under certain engineering, procurement and construction and long-term contracts totaling $14.5 million and invested $8.0 million and $2.6 million in fixed assets and oil and gas drilling activities (net of sales), respectively.

Financing Activities—Net cash provided by financing activities was $363.8 million during the nine months ended September 30, 2007 compared to $336.4 million net cash provided by financing activities during the nine months ended September 30, 2006. During the first nine months of 2007, we received proceeds of $400.0 million from borrowings under the 2007 Term Loan, $203.9 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 Associated Minority Interest” of our Notes to Consolidated Financial Statements for further discussion. These were partially offset by the use of $325.0 million to acquire 9.2 million shares of our common stock under a call spread option and $9.7 million for debt issuance costs associated with the 2007 Term Loan. During the first nine months of 2006, we received proceeds from borrowings under an original Sabine Pass credit agreement and an amended Sabine Pass credit facility totaling $351.5 million, and we received $1.7 million from the issuance of common stock related to stock option exercises. These proceeds were partially offset by $4.5 million in 2007 Term Loan principal payments, $3.0 million in debt issuance costs related to the original Sabine Pass credit agreement, which became due when the first borrowing was made thereunder, and $8.4 million in debt issuance costs related

to the refinancing of the Sabine Pass credit facility during the third quarter of 2006. In addition, we paid federal withholding taxes of $0.9 million in exchange for 24,300 shares of our common stock, which related to common stock previously awarded to an executive officer that vested in February 2006.

Transactions in our Common Stock

During the first nine months of 2007, we issued 308,125 shares of our common stock pursuant to the exercise of stock options, resulting in net cash proceeds of $2.5 million. In addition, we issued 215,759 shares of our common stock in satisfaction of the cashless exercises of options to purchase 241,275 shares of our common stock.

In January 2007, we issued 628,396 shares of our common stock to our employees and executive officers in the form of non-vested (restricted) stock awards related to our performance in 2006. During the first nine months of 2007, we issued an additional 242,755 shares of non-vested restricted stock to new and existing employees.

In May 2007, 30,574 shares of our common stock were issued to our outside directors in the form of non-vested restricted stock awards.

During the first nine months of 2007, we purchased 9,175,595 shares of our common stock for a cash price of $35.42 per share under the call options acquired in the issuer call spread purchased by us in connection with the issuance of the Convertible Senior Unsecured Notes.

Off-Balance Sheet Arrangements

As of September 30, 2007, we had no off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed the debt of any unaffiliated party.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2007

vs. Three Months Ended September 30, 2006

Consolidated Results (in thousands):


	Three Months Ended September 30, 2007
	LNG Receiving Terminal			Natural Gas Pipeline			LNG & Natural Gas Marketing			Oil & Gas Exploration & Development			Corporate & Other			Consolidated
Revenue	$	—		$	—		$	(418	)	$	812		$	—		$	394
Operating costs and expenses
LNG receiving terminal and pipeline development expenses		7,989			2,082			—			—			—			10,071
Exploration costs		—			—			—			659			—			659
Oil and gas production costs		—			—			—			82			—			82
Depreciation, depletion and amortization		106			—			189			342			1,315			1,952
General and administrative expenses		1,354			—			6,547			128			26,875			34,904

Total operating costs and expenses		9,449			2,082			6,736			1,211			28,190			47,668
Loss from operations		(9,449	)		(2,082	)		(7,154	)		(399	)		(28,190	)		(47,274	)
Loss from equity method investments		—			—			—			—			(191	)		(191	)
Interest expense, net		(15,117	)		—			(41	)		—			(12,869	)		(28,027	)
Interest income		12,645			—			721			—			7,624			20,990
Other income (loss)		—			37			1			—			(35	)		3

Loss before income taxes and minority interest		(11,921	)		(2,045	)		(6,473	)		(399	)		(33,661	)		(54,499	)
Minority interest		1,045			—			—			—			—			1,045

Net loss	$	(10,876	)	$	(2,045	)	$	(6,473	)	$	(399	)	$	(33,661	)	$	(53,454	)


	Three Months Ended September 30, 2006
	LNG Receiving Terminal			Natural Gas Pipeline			LNG & Natural Gas Marketing			Oil & Gas Exploration & Development			Corporate & Other			Consolidated
Revenue	$	—		$	—		$	—		$	737		$	—		$	737
Operating costs and expenses
LNG receiving terminal and pipeline development expenses		3,150			(227	)		—			—			—			2,923
Exploration costs		—			—			—			661			—			661
Oil and gas production costs		—			—			—			61			—			61
Impairment of fixed assets		—			—			—			—			1,628			1,628
Depreciation, depletion and amortization		36			—			13			113			734			896
General and administrative expenses		1,305			2			1,292			877			8,568			12,044

Total operating costs and expenses		4,491			(225	)		1,305			1,712			10,930			18,213
Income (loss) from operations		(4,491	)		225			(1,305	)		(975	)		(10,930	)		(17,476	)
Derivative loss		(966	)		—			—			—			—			(966	)
Interest expense, net		(5,662	)		241			—			—			(5,465	)		(10,886	)
Interest income		2,055			—			—			—			9,045			11,100
Other income		—			201			—			—			—			201

Income (loss) before income taxes and minority interest		(9,064	)		667			(1,305	)		(975	)		(7,350	)		(18,027	)
Income tax provision		—			—			—			—			(15,079	)		(15,079	)

Net income (loss)	$	(9,064	)	$	667		$	(1,305	)	$	(975	)	$	(22,429	)	$	(33,106	)

Financial results for the third quarter of 2007 reflect a net loss of $53.5 million, or $1.14 per share (basic and diluted), compared to a net loss of $33.1 million, or $0.61 per share (basic and diluted), for the third quarter of 2006.

The major factors contributing to our net loss of $53.5 million during the third quarter of 2007 were LNG terminal and pipeline development expenses of $10.1 million, general and administrative (“G&A”) expenses of $34.9 million and interest expense, net of amounts capitalized, of $28.0 million. These expenses were partially offset by interest income of $21.0 million. The major factors contributing to our net loss of $33.1 million during the third quarter of 2006 was an income tax provision of $15.1 million, charges for G&A expenses of $12.0 million, interest expense of $10.9 million and LNG receiving terminal and pipeline development expenses of $2.9 million, partially offset by interest income of $11.1 million.

LNG Receiving Terminal Segment

Financial results for our LNG receiving terminal segment for the third quarter of 2007 reflect a net loss of $10.9 million, compared to a net loss of $9.1 million for the third quarter of 2006.

LNG development expenses were $8.0 million in the third quarter of 2007 compared to $3.2 million in the third quarter of 2006. Our development expenses primarily include costs of 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. Other expenses directly related to the development of our LNG receiving terminals include expenses of our LNG employees directly involved in the development activities. The $4.8 million increase in development expenses for the third quarter of 2007 compared to the third quarter of 2006 primarily resulted from an increase in employee-related costs of $2.3 million and $1.9 million in public relations,

offset by decreases in engineering, legal and other technical services due to front-end engineering and design work related to our Corpus Christi and Creole Trail LNG receiving terminals and expansion of our Sabine Pass LNG receiving terminal having been incurred in 2006. The increase in employee-related costs was due to our increase in the average number of LNG receiving terminal employees to 140 in the third quarter of 2007 from 70 in the third quarter of 2006. This increase in employees resulted primarily from the hiring of employees who will ultimately be operating our Sabine Pass LNG receiving terminal. The increase in public relations expenses was due to costs associated with the building of the Johnson Buyou Rural Health Clinc that will be operated by West Calcasieu Cameron Hospital Group to assist the local community in its rebuilding efforts as it continues to recover from Hurricane Rita.

The increase in interest income to $12.6 million in the third quarter of 2007 compared to $2.1 million in the third 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, to $15.1 million in the third quarter of 2007 from $5.7 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 third quarter of 2007 reflect a net loss of $2.0 million, compared to net income of $0.7 million for the third quarter of 2006.

Natural gas pipeline development expenses increased to $2.1 million in the third quarter of 2007 compared to a credit of $0.2 million in the third quarter of 2006. Historically, our natural gas pipeline development expenses primarily included professional fees associated with front-end engineering and design work, obtaining orders from the FERC authorizing construction of our pipelines and other required permitting for our planned natural gas pipelines. During the second quarter of 2006, however, we recognized regulatory assets, as prescribed by Statement of Financial Accounting Standards (“SFAS”) No. 71 that had previously been expensed as pipeline development expenses. The third quarter of 2006 natural gas pipeline development expense includes the deferral of certain engineering and feasibility costs relating to a proposed segment of our Creole Trail Pipeline in accordance with SFAS No. 71. These costs, which had previously been expensed, were deferred and moved into construction-in-process when the FERC application was approved.

LNG and Natural Gas Marketing Segment

Financial results for our LNG and natural gas marketing segment for the third quarter of 2007 reflect a net loss of $6.5 million, compared to a net loss of $1.3 million for the third quarter of 2006.

G&A expenses increased to $6.5 million in the third quarter of 2007 compared to expenses of $1.3 million in the third quarter of 2006. G&A expenses in the third quarter of 2007 were primarily related to employee costs. Our marketing staff increased from an average of 16 employees in the third quarter of 2006 to an average of 47 employees in the third quarter of 2007, resulting in an increase in total compensation expense to $6.1 million (including non-cash compensation of $3.6 million) in the third quarter of 2007 compared to $1.1 million in the third quarter of 2006.

We earned $0.7 million in interest income in the third quarter of 2007 compared to none in the third quarter of 2006 due to an increase in average invested cash balances.

Oil and Gas Exploration and Development Segment

Financial results for our oil and gas exploration and development segment for the third quarter of 2007 reflect a net loss of $0.4 million, compared to a net loss of $1.0 million for the third quarter of 2006. The decrease in net loss was primarily due to a decrease in G&A expenses.

Corporate and Other

Financial results for corporate and other activities for the third quarter of 2007 reflect a net loss of $33.7 million, compared to a net loss of $22.4 million for the third quarter of 2006.

G&A expenses increased $18.3 million to $26.9 million in the third quarter of 2007 compared to $8.6 million in the third quarter of 2006. Our corporate staff increased from an average of 106 employees in the third quarter of 2006 to an average of 152 employees in the third quarter of 2007, resulting in total compensation of $23.1 million (including non-cash compensation of $15.7 million) in the third quarter of 2007 compared to $6.5 million (including non-cash compensation of $3.1 million) in the third quarter of 2006. In addition, we had an increase of $1.7 million in professional fees and other incremental expenses in the third quarter of 2007 compared to the third quarter of 2006.

Interest expense, net of amounts capitalized, was $12.9 million in the third quarter of 2007 compared to $5.5 million in the third quarter of 2006. The increase was due to an increase in the amount of outstanding indebtedness due to the 2007 Term Loan.

Interest income decreased to $7.6 million in the third quarter of 2007 compared to $9.0 million in the third quarter of 2006 due primarily to a decrease in average invested cash balances.

A tax provision of $15.1 million was recognized in the third 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. The deferred tax provision recorded in the third quarter of 2006 was limited to the amount of tax benefit previously recorded, which was reduced to zero in the third quarter of 2006.

Nine Months Ended September 30, 2007

vs. Nine Months Ended September 30, 2006


	Nine Months Ended September 30, 2007
	LNG Receiving Terminal			Natural Gas Pipeline			LNG & Natural Gas Marketing			Oil & Gas Exploration & Development		Corporate & Other			Consolidated
Revenue	$	—		$	—		$	(4,353	)	$	4,362	$	—		$	9
Operating costs and expenses
LNG receiving terminal and pipeline development expenses		22,841			3,516			—			—		—			26,357
Exploration costs		—			—			—			1,032		—			1,032
Oil and gas production costs		—			—			—			250		—			250
Impairment of fixed assets		—			—			—			—		18			18
Depreciation, depletion and amortization		250			—			464			522		3,287			4,523
General and administrative expenses		4,197			134			15,387			118		65,265			85,101

Total operating costs and expenses		27,288			3,650			15,851			1,922		68,570			117,281
Income (loss) from operations		(27,288	)		(3,650	)		(20,204	)		2,440		(68,570	)		(117,272	)
Loss from equity method investments		—			—			—			—		(191	)		(191	)
Interest expense, net		(56,277	)		(281	)		—			—		(23,825	)		(80,383	)
Interest income		42,039			—			1,823			3		22,830			66,695
Other expense		—			—			—			—		(181	)		(181	)

Income (loss) before income taxes and minority interest		(41,526	)		(3,931	)		(18,381	)		2,443		(69,937	)		(131,332	)
Minority interest		2,203			—			—			—		—			2,203

Net income (loss)	$	(39,323	)	$	(3,931	)	$	(18,381	)	$	2,443	$	(69,937	)	$	(129,129	)


	Nine Months Ended September 30, 2006
	LNG Receiving Terminal			Natural Gas Pipeline			LNG & Natural Gas Marketing			Oil & Gas Exploration & Development			Corporate & Other			Consolidated
Revenue	$	—		$	—		$	—		$	1,572		$	—		$	1,572
Operating costs and expenses
LNG receiving terminal and pipeline development expenses		15,540			(8,810	)		—			—			—			6,730
Exploration costs		—			—			—			2,089			—			2,089
Oil and gas production costs		—			—			—			166			—			166
Impairment of fixed assets		—			—			—			—			1,628			1,628
Depreciation, depletion and amortization		100			—			20			172			1,788			2,080
General and administrative expenses		5,389			13			4,124			2,673			25,470			37,669

Total operating costs and expenses		21,029			(8,797	)		4,144			5,100			28,886			50,362
Income (loss) from operations		(21,029	)		8,797			(4,144	)		(3,528	)		(28,886	)		(48,790	)
Derivative loss		(44	)		—			—			—			—			(44	)
Interest expense, net		(17,220	)		371			—			—			(16,271	)		(33,120	)
Interest income		5,906			—			—			—			25,072			30,978
Other income		—			309			—			176			—			485

Income (loss) before income taxes		(32,387	)		9,477			(4,144	)		(3,352	)		(20,085	)		(50,491	)
Income tax provision		—			—			—			—			(2,045	)		(2,045	)

Net income (loss)	$	(32,387	)	$	9,477		$	(4,144	)	$	(3,352	)	$	(22,130	)	$	(52,536	)

Financial results for the nine months ended September 30, 2007 reflect a net loss of $129.1 million, or $2.48 per share (basic and diluted), compared to a net loss of $52.5 million, or $0.97 per share (basic and diluted), for the nine months ended September 30, 2006.

The major factors contributing to our net loss of $129.1 million during the first nine months of 2007 were G&A expenses of $85.1 million, interest expense, net of amounts capitalized, of $80.4 million and LNG receiving terminal and pipeline development expenses of $26.4 million, partially offset by interest income of $66.7 million and minority interest of $2.2 million. The major factors contributing to our net loss of $52.5 million during the first nine months of 2006 were LNG receiving terminal and pipeline development expenses of $6.7 million, G&A expenses of $37.7 million, interest expense, net of amounts capitalized, of $33.1 million, and an income tax provision of $2.0 million offset by interest income of $31.0 million. Included in the $6.7 million of LNG receiving terminal and pipeline development expenses is a credit of $12.3 million representing the amount of pipeline development expenses previously charged to expense that was considered a regulatory asset as a result of our application of SFAS No. 71 in the second quarter of 2006. Our net loss for the first nine months of 2006 excluding the $12.3 million credit was $64.8 million, or $1.19 per share (basic and diluted).

LNG Receiving Terminal Segment

Financial results for our LNG receiving terminal segment for the first nine months of 2007 reflect a net loss of $39.3 million, compared to a net loss of $32.4 million for the first nine months of 2006.

LNG development expenses were $22.8 million in the first nine months of 2007 compared to $15.5 million in the first nine months of 2006. Our development expenses primarily include costs of 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. Other expenses directly related to the development of our LNG receiving terminals include expenses of our LNG employees directly involved in the development activities. The $7.3 million increase in development expenses for the first nine months of 2007 compared to the first nine months of 2006 primarily resulted from an increase in employee-related costs of $6.2 million and $2.7 million in public relations expenses, offset by decreases in engineering, legal and other technical services due to front-end engineering and design work related to our Corpus Christi and Creole Trail LNG receiving terminal and expansion of our Sabine Pass LNG receiving terminal having been incurred in 2006. The increase in employee-related costs was due to our increase in the average number of LNG receiving terminal employees to 121 in the first nine months of 2007 from 57 in the first nine months of 2006. This increase resulted primarily from the hiring of employees who will ultimately be operating our Sabine Pass LNG receiving terminal. The increase in public relations expenses was due to costs associated with the building of the Johnson Bayou Rural Health Clinic that will be operated by West Calcasieu Cameron Hospital Group to assist the local community in its rebuilding efforts as it continues to recover from Hurricane Rita.

G&A expenses were $4.2 million in the first nine months of 2007 compared to $5.4 million in the first nine months of 2006. The $1.2 million decrease between periods was primarily due to an increase in capitalized labor costs associated with the Sabine Pass LNG receiving terminal and the terminal operations management system implemented for our LNG receiving terminals and lower public relations expenses and other professional costs related to software evaluation costs.

Interest income and interest expense, net of amounts capitalized, increased $36.1 million and $39.1 million, respectively, from the first nine months of 2006 compared to the first nine months of 2007. The increase in interest income was due to investment income on the net proceeds received from the Sabine Pass LNG notes issued in November 2006. Similarly, the increase in interest expense, net of amounts capitalized, was due to the interest expense paid on the Sabine Pass LNG notes.

Natural Gas Pipeline Segment

Financial results for our natural gas pipeline segment for the first nine months of 2007 reflect a net loss of $3.9 million, compared to net income of $9.5 million for the first nine months of 2006.

Natural gas pipeline development expenses increased $12.3 million in the first nine months of 2007 to $3.5 million compared to a negative $8.8 million in the first nine months of 2006. Historically, our natural gas pipeline development expenses primarily included professional fees 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 natural gas pipelines. During the first nine months of 2006, however, we recognized regulatory assets, as prescribed by SFAS No. 71, that had previously been expensed as pipeline development expenses. The impact of recording these regulatory assets reduced pipeline development expenses in the first nine months of 2006 by $12.3 million. Natural gas pipeline development expenses for the first nine months of 2006, excluding the impact of recording regulatory assets, would have been $3.5 million. Excluding the impact of the recognition of regulatory assets in the first nine months of 2006, there was no change between the periods.

LNG and Natural Gas Marketing Segment

Financial results for our LNG and natural gas marketing segment for the first nine months of 2007 reflect a net loss of $18.4 million, compared to a net loss of $4.1 million for the first nine months of 2006. We incurred a marketing and trading loss of $4.4 million in the first nine months of 2007 compared to none in the first nine months of 2006.

G&A expenses were $15.4 million in the first nine months of 2007 compared to $4.1 million in the first nine months of 2006. Our G&A expenses increased primarily due to employee costs. The increase in employee-related costs was due to our increase in the average number of LNG and natural gas marketing employees to 40 in the first nine months of 2007 from 12 in the first nine months of 2006, resulting in an increase in total

compensation expense of $13.5 million (including non-cash compensation of $6.8 million) in the first nine months of 2007 compared to $2.8 million (including non-cash compensation of $0.9 million) in the first nine months of 2006. This increase in employees resulted from the continued development of our LNG and natural gas marketing business.

We earned $1.8 million in interest income in the first nine months of 2007 compared to none in the first nine months of 2006 due to interest income on unutilized cash balances.

Oil and Gas Exploration and Development Segment

Financial results for our oil and gas exploration and development segment for the first nine months of 2007 reflect a net income of $2.4 million, compared to a net loss of $3.4 million for the first nine months of 2006. The increase in net income was a result of an increase in production volumes from the addition of a successful well, the favorable settlement of a disputed overriding royalty interest, and a decrease in exploration costs and general and administrative expenses.

Corporate and Other

Financial results for our corporate and other activities for the first nine months of 2007 reflect a net loss of $69.9 million, compared to net loss of $22.1 million for the first nine months of 2006.

G&A expenses increased $39.8 million to $65.3 million in the first nine months of 2007 compared to $25.5 million in the first nine months of 2006. Our corporate staff increased from an average of 89 employees in the first nine months of 2006 to an average of 140 employees in the first nine months of 2007, resulting in higher total compensation of $50.4 million (including non-cash compensation of $29.1 million) in the first nine months of 2007 compared to $18.4 million (including non-cash compensation of $9.5 million) in the first nine months of 2006. In addition, we had an increase of $7.8 million in professional fees and other in the first nine months of 2007 compared to the first nine months of 2006.

Interest expense, net of amounts capitalized, was $23.8 million in the first nine months of 2007 compared to $16.3 million in the first nine months of 2006. The increase was primarily a result of the 2007 Term Loan entered into in May 2007.

Interest income decreased to $22.8 million in the first nine months of 2007 compared to $25.1 million in the first nine months of 2006 due to a decrease in average invested cash balances, primarily as a result of repayment of the Holdings term loan in November 2006, partially offset by the investment of funds received from the 2007 Term Loan in May 2007.

A tax provision of $2.0 million was recognized in the first nine months of 2006 relating to the portion of the change in our tax asset valuation account that is allocable to the deferred income tax on items reported in accumulated other comprehensive income on derivative instruments in accordance with SFAS No. 109, Accounting for Income Taxes, and EITF Abstracts, Topic D-32.

OTHER MATTERS

Critical Accounting Estimates and Policies

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives but involve an implementation and interpretation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to comply properly with all applicable rules on or before their adoption, and we believe that the proper implementation and consistent application of the accounting rules are critical. However, not all situations are specifically addressed in the accounting literature. In these cases, we must use our best judgment to adopt a policy for accounting for these situations. We accomplish this by analogizing to similar situations and the accounting guidance governing them.

Accounting for LNG Activities

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

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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 other comprehensive income, 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. 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.

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 use various methods to estimate the fair value of share-based payment awards depending on the characteristics of the award. 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.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Marketing and Trading Commodity Price Risk

Through Cheniere Marketing, we have natural gas marketing and trading positions accounted for as derivatives. We use value at risk (“VaR”) and other methodologies for market risk measurement and control purposes. For the three and nine months ended September 30, 2007, the one-day VaR with a 95% confidence interval of our marketing and trading derivative positions averaged $0.1 million and $0.2 million, respectively. At September 30, 2007, the one-day VaR of our marketing and trading derivative positions was $0.1 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 Sheets.

Item 4.

Disclosure Controls and Procedures

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’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 their evaluation as of the end of the fiscal quarter ended September 30, 2007, our Chief Executive Officer and our Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

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 regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, as of September 30, 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. In the future, we may be involved as a party to various legal proceedings, which are incidental to the ordinary course of business.

Item 6.

Exhibits

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


10.1		Change Order 50 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation.

10.2		Change Orders 4, 5, 6, 7, 8, 9, 10 and 11 to Construction Agreement, dated January 10, 2007, between Cheniere Creole Trail Pipeline, L.P. and Sheehan Pipe Line Construction Company.

10.3		Change Orders 2, 3 and 7 to Construction Agreement, dated January 5, 2007, between Cheniere Creole Trail Pipeline, L.P. and Sunland Construction, Inc.

10.4		Change Order 6 to Engineer, Procure and Construct (EPC) LNG Unit Rate Soil Contract, dated July 21, 2006, between Sabine Pass LNG, L.P. and Remedial Construction Services, L.P.

10.5		Change Orders 2 and 3 to Agreement for Engineering, Procurement, Construction and Management of Construction Services for the Sabine Phase 2 Receiving, Storage and Regasification Terminal Expansion, dated July 21, 2006, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.38 to Sabine Pass LNG, L.P.’s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on June 11, 2007).

10.6		Change Order 1, 2 and 3 to Engineer, Procure and Construct (EPC) LNG Tank Contract, dated July 21, 2006, between Sabine Pass LNG, L.P., Zachry Construction Corporation and Diamond LNG LLC (incorporated by reference to Exhibit 10.37 to Sabine Pass LNG, L.P.’s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on June 11, 2007).

10.7		Cooperative Endeavor Agreement & Payment in Lieu of Tax Agreement, dated October 23, 2007 (amending the Amended and Restated Terminal Use Agreement, dated November 9, 2006, by and 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/ DON A. TURKLESON

Don A. Turkleson

Senior Vice President and Chief Financial Officer

(on behalf of the registrant and

as principal accounting officer)

Date: November 6, 2007