Edgar Filing: CHENIERE ENERGY INC

form_10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2010

¨	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	95-4352386
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

700 Milam Street, Suite 800
Houston, Texas	77002
(Address of principal executive offices)	(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 S No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer ¨	Accelerated filer S
Non-accelerated filer ¨	Smaller reporting company ¨
(Do not check if a smaller reporting company)

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

As of August 2, 2010, there were 57,626,649 shares of Cheniere Energy, Inc. Common Stock, $0.003 par value, issued and outstanding.

CHENIERE ENERGY, INC.

INDEX TO FORM 10-Q

PART I. FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements	1
	Consolidated Balance Sheets	1
	Consolidated Statements of Operations	2
	Consolidated Statement of Equity (Deficit)	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	16

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33

Item 4.	Disclosure Controls and Procedures	33

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	34

Item 6.	Exhibits	34

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

	June 30, 2010			December 31, 2009
ASSETS	(unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	73,940		$	88,372
Restricted cash and cash equivalents		76,164			138,309
LNG inventory		501			32,602
Accounts and interest receivable		21,565			9,899
Prepaid expenses and other		18,526			17,093
TOTAL CURRENT ASSETS		190,696			286,275

NON-CURRENT RESTRICTED CASH AND CASH EQUIVALENTS		82,892			82,892
PROPERTY, PLANT AND EQUIPMENT, NET		2,187,044			2,216,855
DEBT ISSUANCE COSTS, NET		41,347			47,043
GOODWILL		76,819			76,819
INTANGIBLE LNG ASSETS		6,067			6,088
OTHER		22,616			16,650
TOTAL ASSETS	$	2,607,481		$	2,732,622

LIABILITIES AND DEFICIT
CURRENT LIABILITIES
Accounts payable	$	723		$	426
Accrued liabilities		28,233			38,425
Deferred revenue		26,453			26,456
Other		1,108			905
TOTAL CURRENT LIABILITIES		56,517			66,212

LONG-TERM DEBT, NET OF DISCOUNT		2,593,386			2,692,740
LONG-TERM DEBT—RELATED PARTIES, NET OF DISCOUNT		309,495			349,135
DEFERRED REVENUE		31,773			33,500
OTHER NON-CURRENT LIABILITIES		2,875			23,162
COMMITMENTS AND CONTINGENCIES		—			—

DEFICIT
Stockholders’ deficit
Preferred stock, $.0001 par value, 5,000,000 shares authorized, none issued		—			—
Common stock, $.003 par value
Authorized: 240,000,000 and 240,000,000 shares at June 30, 2010 and December 31, 2009, respectively
Issued and outstanding: 57,627,000 and 56,651,000 shares at June 30, 2010 and December 31, 2009, respectively		173			170
Treasury stock: 924,000 and 697,000 shares at June 30, 2010 and December 31, 2009, respectively, at cost		(2,175	)		(1,494	)
Additional paid-in-capital		346,954			336,971
Accumulated deficit		(934,736	)		(985,246	)
Accumulated other comprehensive loss		(203	)		(133	)
TOTAL STOCKHOLDERS’ DEFICIT		(589,987	)		(649,732	)
Non-controlling interest		203,422			217,605
TOTAL DEFICIT		(386,565	)		(432,127	)
TOTAL LIABILITIES AND DEFICIT	$	2,607,481		$	2,732,622

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 June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
REVENUES
LNG receiving terminal revenues	$	66,337		$	38,201		$	133,164		$	38,201
Oil and gas sales		884			839			1,421			1,573
Marketing and trading		1,029			(1,156	)		13,170			(656	)
Other		25			75			37			75
TOTAL REVENUES		68,275			37,959			147,792			39,193

OPERATING COSTS AND EXPENSES
LNG receiving terminal and pipeline development expense		1,143			91			1,861			—
LNG receiving terminal and pipeline operating expense		9,807			9,251			22,619			18,029
Oil and gas production and exploration costs		113			77			211			164
Depreciation, depletion and amortization		15,612			12,795			31,236			24,857
General and administrative expense		16,910			15,422			36,128			33,219
TOTAL OPERATING COSTS AND EXPENSES		43,585			37,636			92,055			76,269

INCOME (LOSS) FROM OPERATIONS		24,690			323			55,737			(37,076	)

OTHER INCOME (EXPENSE)
Gain on sale of equity method investment		128,329			—			128,329			—
Derivative gain (loss), net		(44	)		762			461			3,324
Gain (loss) on early extinguishment of debt		(1,011	)		45,363			(1,011	)		45,363
Interest expense, net		(66,950	)		(61,959	)		(134,145	)		(115,209	)
Interest income		142			388			239			1,199
Other income (loss)		16			46			(87	)		(17	)
TOTAL OTHER INCOME (EXPENSE)		60,482			(15,400	)		(6,214	)		(65,340	)
INCOME (LOSS) BEFORE INCOME TAXES		85,172			(15,077	)		49,523			(102,416	)
INCOME TAX PROVISION		—			—			—			—
NET INCOME (LOSS)		85,172			(15,077	)		49,523			(102,416	)
NET LOSS ATTRIBUTABLE TO NON-CONTROLLING INTEREST		505			2,026			987			6,624
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	85,677		$	(13,051	)	$	50,510		$	(95,792	)

Net income (loss) per share attributable to common stockholders—basic	$	1.55		$	(0.25	)	$	0.92		$	(1.91	)
Net income (loss) per share attributable to common stockholders—diluted	$	0.86		$	(0.25	)	$	0.62		$	(1.91	)
Weighted average number of common shares outstanding—basic		55,317			51,576			55,161			50,121
Weighted average number of common shares outstanding—diluted		116,596			51,576			110,610			50,121

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY (DEFICIT)

(in thousands)

(unaudited)

																Accumulated
										Additional						Other			Non-			Total
	Common Stock				Treasury Stock					Paid-in			Accumulated			Comprehensive			controlling			Equity
	Shares			Amount	Shares		Amount			Capital			Deficit			Loss			Interest			(Deficit)

Balance—December 31, 2009	56,651		$	170	697	$	(1,494	)	$	336,971		$	(985,246	)	$	(133	)	$	217,605		$	(432,127	)
Issuances of restricted stock	1,203			3	—		—			(3	)		—			—			—			—
Forfeitures of restricted stock	(23	)		—	23		—			—			—			—			—			—
Stock-based compensation	—			—	—		—			9,985			—			—			—			9,985
Treasury stock acquired	(204	)		—	204		(681	)		1			—			—			—			(680	)
Comprehensive income: Foreign currency translation	—			—	—		—			—			—			(70	)		—			(70	)
Loss attributable to non-controlling interest	—			—	—		—			—			—			—			(987	)		(987	)
Distribution to non-controlling interest	—			—	—		—			—			—			—			(13,196	)		(13,196	)
Net income attributable to common stockholders	—			—	—		—			—			50,510			—			—			50,510
Balance— June 30, 2010	57,627		$	173	924	$	(2,175	)	$	346,954		$	(934,736	)	$	(203	)	$	203,422		$	(386,565	)

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Six Months Ended June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) attributable to common stockholders	$	50,510		$	(95,792	)
Adjustments to reconcile net income (loss) attributable to common stockholders to net cash used in operating activities:
Gain on sale of limited partnership investment		(128,329	)		—
(Gain) loss on early extinguishment of debt		1,011			(45,363	)
Depreciation, depletion and amortization		31,236			24,857
Amortization of debt issuance and debt discount		13,705			14,896
Non-cash compensation		9,945			8,645
Restricted interest income on restricted cash and cash equivalents		—			(2,774	)
Use of restricted cash and cash equivalents		41,250			49,158
Non-cash derivative loss		164			223
Non-controlling interest		(987	)		(6,624	)
Non-cash interest expense		17,428			15,565
Use of cash for accrued interest		(60,899	)		—
Other		(4,668	)		(118	)
Changes in operating assets and liabilities:
Accounts payable and accrued liabilities		(3,539	)		116
LNG inventory		32,100			(10,699	)
Accounts and interest receivable		(16,190	)		1,657
Deferred revenue		(2,086	)		21,738
Prepaid expenses and other		(1,255	)		(3,128	)
NET CASH USED IN OPERATING ACTIVITIES		(20,604	)		(27,643	)

CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of limited partnership investment		104,330			—
Use of restricted cash and cash equivalents		4,214			71,088
LNG terminal and pipeline construction-in-process, net		(3,065	)		(81,175	)
Distributions from limited partnership investment		3,900			6,600
Purchases of LNG commissioning, net of amounts transferred to LNG terminal construction-in-process		—			(14,184	)
Purchases of intangibles and fixed assets, net of sales		326			(140	)
Other		(106	)		(2,844	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		109,599			(20,655	)

CASH FLOWS FROM FINANCING ACTIVITIES
Use of restricted cash and cash equivalents		16,680			78,391
Distributions to non-controlling interest		(13,196	)		(13,196	)
Debt repurchases		(104,681	)		(30,030	)
Purchase of treasury shares		(681	)		(80	)
Other		(1,549	)		(33	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(103,427	)		35,052

NET DECREASE IN CASH AND CASH EQUIVALENTS		(14,432	)		(13,246	)
CASH AND CASH EQUIVALENTS—beginning of period		88,372			102,192
CASH AND CASH EQUIVALENTS—end of period	$	73,940		$	88,946

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

Results of operations for the three and six-month periods ended June 30, 2010 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2010.

Certain reclassifications have been made to prior period information to conform to the current presentation. The reclassifications had no effect on our overall consolidated financial position, results of operations or cash flows.

For further information, refer to the consolidated financial statements and accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2009.

Liquidity

As of June 30, 2010, we had unrestricted cash and cash equivalents of $73.9 million and accounts receivable and other working capital from LNG and natural gas marketing activities of approximately $28 million that will be available to Cheniere, which excludes cash and cash equivalents available to Cheniere Energy Partners, L.P. (“Cheniere Partners”), a publicly traded partnership in which we own a 90.6% interest, and Sabine Pass LNG, L.P. (“Sabine Pass LNG”), a wholly-owned subsidiary of Cheniere Partners. In addition, we had restricted cash and cash equivalents of $159.1 million, which were designated for the following purposes: $17.0 million for Sabine Pass LNG’s working capital; $43.1 million for Cheniere Partners’ working capital; $96.1 million for interest payments related to the Senior Notes described below; and $2.9 million for other restricted purposes. Although results are consolidated for financial reporting, Cheniere, Sabine Pass LNG and Cheniere Partners operate with independent capital structures. We believe that we have sufficient cash, other working capital and cash generated from our operations to fund our operating expenses and other cash requirements until the earliest date when principal payments may be required. The lenders of the 2008 Convertible Loans can require prepayment of the loans between August 16, 2011 and September 14, 2011 (See Note 9—“Long-Term Debt and Long-Term Debt—Related Parties”). If the lenders of the 2008 Convertible Loans do not require the principal payment in 2011, the earliest date that principal payments will be required is May 31, 2012, which is the maturity date of the 2007 Term Loan. Before our first required principal payment, we will need to restructure our finances and improve our capital structure, which may be accomplished by entering into long-term TUAs or LNG purchase agreements, refinancing our existing indebtedness, issuing equity or other securities, selling assets or a combination of the foregoing.

Our ability to enhance near-term liquidity and improve our capital structure is dependent on numerous factors, including the availability of credit, the balance of worldwide and domestic supply and demand for natural gas and LNG, and the relative prices for natural gas in North America and international markets. We face numerous financial, market and operational risks in connection with improving our liquidity situation, many of which are beyond our control.

NOTE 2—Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consist of cash and cash equivalents that are contractually restricted as to usage or withdrawal, as follows:

Senior Notes Debt Service Reserve

Sabine Pass LNG consummated private offerings of an aggregate principal amount of $2,215.5 million of Senior Notes (See Note 9—“Long-Term Debt and Long-Term Debt—Related Parties”). Under the indenture governing the Senior Notes (the “Sabine Pass Indenture”), except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

debt service reserve fund an amount equal to one semi-annual interest payment of approximately $82.4 million. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass Indenture. As of June 30, 2010 and December 31, 2009, we classified the permanent debt service reserve fund of $82.4 million as non-current restricted cash and cash equivalents. As of June 30, 2010 and December 31, 2009, we classified $13.7 million as current restricted cash and cash equivalents for the payment of interest due within twelve months. These cash accounts are controlled by a collateral trustee, and therefore, are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.

TUA Reserve

Under the original terms and conditions of the 2008 Convertible Loans described below in Note 9—“Long-Term Debt and Long-Term Debt—Related Parties”, we were required to fund a reserve account (“TUA Reserve Account”) with $135.0 million to pay obligations of Cheniere Marketing, LLC (“Cheniere Marketing”) under its Terminal Use Agreement (“TUA”) with Sabine Pass LNG and as additional collateral for the 2008 Convertible Loans. The cash account is controlled by a collateral trustee, and therefore, is shown as restricted cash and cash equivalents on our Consolidated Balance Sheet as of December 31, 2009.

In June 2010, we amended the 2008 Convertible Loans to permit all funds on deposit in the TUA Reserve Account to be applied to the prepayment of the accrued interest on the loans outstanding under the 2008 Convertible Loans, with any remainder to be applied to the prepayment of the principal balance of such 2008 Convertible Loans. As a result, $63.6 million from the TUA Reserve Account was applied to such prepayment, leaving the balance of the TUA Reserve Account at zero at June 30, 2010.

Other Restricted Cash and Cash Equivalents

As of June 30, 2010 and December 31, 2009, $60.1 million and $124.4 million, respectively, of cash and cash equivalents was primarily related to cash and cash equivalents held by Sabine Pass LNG and Cheniere Partners that is considered restricted to Cheniere. As of June 30, 2010 and December 31, 2009, due to various other contractual restrictions, $76.2 million and $138.3 million had been classified as current restricted cash and cash equivalents, respectively, and $0.5 million had been classified as non-current restricted cash and cash equivalents on our Consolidated Balance Sheets.

NOTE 3—LNG Inventory

LNG inventory is recorded at cost and is subject to the lower of cost or market (“LCM”) adjustments at the end of each period. Inventory cost is determined using the average cost method. Recoveries of losses resulting from interim period LCM adjustments are recorded when market price recoveries occur on the same inventory in the same fiscal year. These recoveries are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. As of June 30, 2010 and December 31, 2009, we had 143,000 million British thermal units (“MMBtu”) of LNG inventory recorded at $0.5 million and 7,778,000 MMBtu of LNG inventory recorded at $32.6 million on our Consolidated Balance Sheets, respectively.

NOTE 4—Variable Interest Entity

In March 2010, Cheniere Marketing entered into various agreements (“LNGCo Agreements”) with JPMorgan LNG Co. (“LNGCo”), an indirect subsidiary of JPMorgan Chase & Co., effective April 1, 2010, providing Cheniere Marketing with financial support to source more cargos of LNG than it could source on a stand-along basis. Under the LNGCo Agreements, Cheniere Marketing has agreed to develop and maintain commercial and trading opportunities in the LNG industry and present any such opportunities exclusively to LNGCo. In addition, Cheniere Marketing is responsible for providing operational and administrative services to LNGCo in exchange for a portion of the risk and return of certain assets and operating results of LNGCo. In return for the services to be provided by Cheniere Marketing, LNGCo pays a fixed fee to Cheniere Marketing, and may pay additional fees dependent upon the gross margins of each transaction, and the aggregate revenue earned during the term of the various agreements. In the event LNGCo incurs operating losses on its LNG cargo activities, Cheniere Marketing would be responsible for funding a portion of these operating losses. Cheniere Marketing holds no ownership interest in LNGCo and does not have the authority to contractually bind LNGCo under the LNGCo Agreements. LNGCo has various operational responsibilities and unilateral participating rights to direct the activities of LNGCo that most significantly impact LNGCo’s economic performance. The term of the LNGCo Agreements is two years; however, either party may terminate without penalty at the end of one year. We have determined that LNGCo is a variable interest entity (“VIE”), for which Cheniere Marketing is not the primary beneficiary because Cheniere Marketing has a portion of the risk and return of certain assets and operating results of LNGCo, but holds no equity in LNGCo and does not have substantive decision making ability. As a result, we have not consolidated LNGCo into Cheniere’s financial statements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

In April 2010, Cheniere Marketing sold its remaining LNG inventory of 2,415,000 MMBtu to LNGCo.

During the three and six months ended June 30, 2010, we recognized $3.1 million of marketing and trading revenues from LNGCo, which included $0.9 million of revenue recognized on the sale of our inventory to LNGCo. As of June 30, 2010, Cheniere Marketing’s maximum exposure to loss relating to LNGCo was $3.0 million, related to margin deposits that have been paid to LNGCo and fixed fee and gross margin revenue receivables that have been earned as of June 30, 2010. A portion of this $3.0 million represents our fixed fee receivable and is reported as Current Accounts and Interest Receivable, and the remaining portion is reported as Other Non-Current Assets and is to be paid to Cheniere Marketing upon the completion or termination of the LNGCo Agreements.

NOTE 5—Property, Plant and Equipment

Property, plant and equipment consist of LNG terminal and natural gas pipeline costs, LNG site and related costs, investments in oil and gas properties, and fixed assets, as follows (in thousands):

	June 30,			December 31,
	2010			2009
LNG TERMINAL COSTS
LNG receiving terminal	$	1,638,339		$	1,637,542
LNG receiving terminal construction-in-process		37,989			37,120
LNG site and related costs, net		2,992			2,994
Accumulated depreciation		(61,164	)		(40,200	)
Total LNG receiving terminal costs		1,618,156			1,637,456

NATURAL GAS PIPELINE COSTS
Natural gas pipeline		563,683			564,213
Natural gas pipeline construction-in-process		2,419			1,995
Pipeline right-of-ways		18,455			18,455
Accumulated depreciation		(30,451	)		(23,004	)
Total natural gas pipeline costs		554,106			561,659

OIL AND GAS PROPERTIES, successful efforts method
Proved		3,857			3,565
Accumulated depreciation, depletion and amortization		(2,133	)		(1,787	)
Total oil and gas properties, net		1,724			1,778

FIXED ASSETS
Computers and office equipment		5,823			5,799
Furniture and fixtures		5,291			5,291
Computer software		12,325			12,284
Leasehold improvements		8,537			9,258
Other		1,442			1,488
Accumulated depreciation		(20,360	)		(18,158	)
Total fixed assets, net		13,058			15,962

PROPERTY, PLANT AND EQUIPMENT, NET	$	2,187,044		$	2,216,855

LNG Terminal Costs

Depreciation expense related to the Sabine Pass LNG receiving terminal totaled $10.5 million and $7.0 million for the three-month periods ended June 30, 2010 and 2009, respectively; and totaled $21.0 million and $13.6 million for the six-month periods ended June 30, 2010 and 2009, respectively.

Natural Gas Pipeline Costs

Depreciation expense related to our Creole Trail pipeline totaled $3.8 million and $3.7 million for each of the three-month periods ended June 30, 2010 and 2009, and totaled $7.5 million and $7.4 million for each of the six-month periods ended June 30, 2010 and 2009.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

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 fixed assets totaled $1.1 million and $1.6 million for the three-month periods ended June 30, 2010 and 2009, respectively; and totaled $2.5 million and $3.3 million for the six-month periods ended June 30, 2010 and 2009, respectively.

NOTE 6—Non-controlling Interest

We have consolidated our interest in Cheniere Partners because we have a controlling interest in the partnership. Therefore, Cheniere Partners’ financial statements are consolidated in our consolidated financial statements and its other equity is recorded as a non-controlling interest. The following table sets forth the components of our non-controlling interest balance attributable to third-party investors’ interest (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 Cheniere Partners’ non-controlling interest		(79,611	)
Non-controlling interest share of loss of Cheniere Partners		(19,355	)
Non-controlling interest as of June 30, 2010	$	203,422

(1)

In March and April 2007, we and Cheniere Partners completed a public offering of 15,525,000 Cheniere Partners common units (“Cheniere Partners Offering”). Through the Cheniere Partners Offering, Cheniere Partners received $98.4 million in net proceeds from the issuance of its common units to the public. Prior to January 1, 2009, a company was able to 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. Effective January 1, 2009, the sale of common equity of a subsidiary is accounted for as an equity transaction.

(2)

In conjunction with the Cheniere Partners Offering, Cheniere LNG Holdings LLC (“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 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 non-controlling interest.

NOTE 7—Investment in Limited Partnership

In May 2010, we sold our 30% interest in Freeport LNG Development, L.P. (“Freeport LNG”) to institutional investors for net proceeds of $104.3 million. We accounted for our investment in Freeport LNG using the equity method of accounting. Upon closing of the sale, we had unrecorded cumulative suspended losses related to our investment in Freeport LNG, as the basis in our investment had been reduced to zero. During our investment, we received $24.0 million in distributions in excess of our share of income (losses); therefore, we presented the distributions as a long-term liability representing a negative equity investment on our Consolidated Balance Sheets. As a result of the sale, we recognized a net $128.3 million gain. The gain was comprised of net proceeds received of $104.3 million, and $24.0 million in distributions in excess of income.

NOTE 8—Accrued Liabilities

As of June 30, 2010 and December 31, 2009, accrued liabilities consisted of the following (in thousands):

	June 30,		December 31,
	2010		2009
Accrued interest expense and related debt fees	$	16,152	$	16,179
Payroll		5,814		11,118
LNG terminal construction and operating costs		1,520		10,335
Other accrued liabilities		4,747		793
Total accrued liabilities	$	28,233	$	38,425

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

NOTE 9—Long-Term Debt and Long-Term Debt—Related Parties

As of June 30, 2010 and December 31, 2009, our long-term debt consisted of the following (in thousands):

	June 30,			December 31,
	2010			2009
Long-term debt (including related parties):
Senior Notes (including related parties)	$	2,215,500		$	2,215,500
2007 Term Loan		298,000			400,000
2008 Convertible Loans (including related parties)		247,563			293,714
Convertible Senior Unsecured Notes		204,630			204,630
Total long-term debt		2,965,693			3,113,844
Debt discount:
Senior Notes (including related parties)		(30,124	)		(32,471	)
Convertible Senior Unsecured Notes		(32,688	)		(39,498	)
Total debt discount		(62,812	)		(71,969	)
Long-term debt (including related parties), net of discount	$	2,902,881		$	3,041,875

Sabine Pass LNG Senior Notes

In November 2006, Sabine Pass LNG issued an aggregate principal amount of $2,032.0 million of Senior Notes, consisting of $550.0 million of 7¼% Senior Secured Notes due 2013 (the “2013 Notes”) and $1,482.0 million of 7½% Senior Secured Notes due 2016 (the “2016 Notes” and collectively with the 2013 Notes, the “Senior Notes”). In September 2008, Sabine Pass LNG issued an additional $183.5 million, before discount, of 2016 Notes whose terms were identical to the previously outstanding 2016 Notes. The net proceeds received from the additional issuance of 2016 Notes were $145.0 million. The additional issuance and the previously outstanding 2016 Notes are treated as a single series of notes under the Sabine Pass Indenture.

Interest on the Senior Notes is payable semi-annually in arrears on May 30 and November 30 of each year. The Senior Notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG’s equity interests and substantially all of its operating assets. Under the Sabine Pass Indenture, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment of $82.4 million. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass Indenture. During the three and six-month periods ended June 30, 2010, Sabine Pass LNG made distributions of $105.1 million and $211.8 million, respectively, to Cheniere Partners after satisfying all of the applicable conditions in the Sabine Pass Indenture. During the three and six-month periods ended June 30, 2009, Sabine Pass LNG made distributions of $73.0 million and $149.3 million, respectively, to Cheniere Partners after satisfying all of the applicable conditions in the Sabine Pass Indenture.

As of June 30, 2010 and December 31, 2009, we classified $74.1 million and $72.9 million, respectively, as part of Long-Term Debt—Related Party on our Consolidated Balance Sheets because related parties held these portions of the Senior Notes.

Convertible Senior Unsecured Notes

In July 2005, we consummated a private offering of $325.0 million aggregate principal amount of Convertible Senior Unsecured Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. The notes bear interest at a rate of 2¼% per year and mature in August 2012. 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 June 30, 2010, no holders had elected to convert their notes at the conversion rate.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

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 securities rate plus 50 basis points. The indenture governing the notes contains customary reporting requirements.

On January 1, 2009, we adopted an accounting standard that requires issuers of certain convertible debt instruments to separately account for the liability component and the equity component represented by the embedded conversion option in a manner that will reflect that entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The following table summarizes the liability component of the Convertible Senior Unsecured Notes (in thousands):

	June 30, 2010			December 31, 2009
Principal amount	$	204,630		$	204,630
Unamortized discount		(32,688	)		(39,498	)
Net carrying amount	$	171,942		$	165,132

The unamortized discount is being amortized through the August 2012 maturity of the Convertible Senior Unsecured Notes. Interest expense for the Convertible Senior Unsecured Notes, including the debt discount amortization, for the six-month periods ended June 30, 2010 and 2009 was $9.4 million and $12.3 million, respectively. The effective interest rate as of June 30, 2010 was 10.9% for the Convertible Senior Unsecured Notes.

2007 Term Loan

In May 2007, Cheniere Subsidiary Holdings, LLC (“Cheniere Subsidiary”), a 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 9¾% 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. The 2007 Term Loan will mature on May 31, 2012. The 2007 Term Loan is secured by a pledge of our 135,383,831 subordinated units in Cheniere Partners.

In May 2010, we sold our 30% interest in Freeport LNG, which was pledged as security of the 2007 Term Loan, to institutional investors for net proceeds of $104.3 million. The net proceeds from the sale were used to prepay $102.0 million of the 2007 Term Loan in May 2010 (see Note 7—“Investment in Limited Partnership” for additional information). As of June 30, 2010 and December 31, 2009, $298.0 million and $400.0 million, respectively, were outstanding under the 2007 Term Loan and were included in Long-term Debt on our Consolidated Balance Sheets.

2008 Convertible Loans

In August 2008, we entered into a credit agreement pursuant to which we obtained $250.0 million in convertible term loans (“2008 Convertible Loans”). The 2008 Convertible Loans will mature in 2018, but the lenders can require prepayment of the loan for 30 days following August 15, 2011, 2013 and 2015, and upon a change of control. The 2008 Convertible Loans bear interest at a fixed rate of 12% per annum, except during the occurrence of an event of default during which time the rate of interest will be 14% per annum. Interest is due semi-annually on the last business day of January and July. At our option, until August 15, 2011, accrued interest may be added to the principal on each semi-annual interest date. The aggregate amount of all accrued interest to August 15, 2011 will be payable upon the maturity date. The 2008 Convertible Loans are secured by Cheniere’s rights and fees payable under management services agreements with Sabine Pass LNG and Cheniere Partners, by Cheniere’s 10.9 million common units in Cheniere Partners, by the equity and non-real property assets of Cheniere’s pipeline entities, by the equity of various other subsidiaries and certain other assets and subsidiary guarantees. The original principal amount of $250.0 million may be exchanged for newly-created Series B Convertible Preferred Stock, par value $0.0001 per share (“Series B Preferred Stock”), with voting rights limited to the equivalent of 10,125,000 shares of common stock. The exchange ratio is one share of Series B Preferred Stock for each $5,000 of outstanding borrowings, subject to adjustment. The aggregate preferred stock is exchangeable into 50 million shares of common stock at a price of $5.00 per share pursuant to a broadly syndicated offering. No portion of any accrued interest is eligible for conversion into Series B Preferred Stock.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

As long as the 2008 Convertible Loans are exchangeable for shares of Series B Preferred Stock or shares of Series B Preferred Stock remain outstanding, the holders of a majority of the 2008 Convertible Loans and Series B Preferred Stock, acting together, have the right to nominate two individuals to the Company’s Board of Directors, and together with the Board of Directors, a third nominee, who would be an independent director. In addition, one of the lenders is Scorpion Capital Partners LP, an affiliate of one of the Company’s directors.

In June 2010, the 2008 Convertible Loans were amended to permit all funds on deposit in the TUA Reserve Account to be applied to the prepayment of the accrued interest on the loans outstanding under the 2008 Convertible Loans, with any remainder to be applied to the prepayment of the principal balance of such 2008 Convertible Loans. As a result, $63.6 million from the TUA Reserve Account was used to prepay $60.9 million of accrued interest and $2.7 million of principal.

As of June 30, 2010 and December 31, 2009, $235.4 million and $276.2 million, respectively, were outstanding under the 2008 Convertible Loans and were included in Long-term Debt—Related Party on our Consolidated Balance Sheets.

NOTE 10—Financial Instruments

We entered into financial derivatives to hedge the exposure to variability in expected future cash flows and currency fluctuations attributable to the future sale of LNG inventory. Changes in the fair value of our derivatives are reported in earnings because they do not meet the criteria to be designated as a hedging instrument that is required to qualify for cash flow hedge accounting. In addition, we entered into financial derivatives in order to take market positions associated with LNG and natural gas.

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The fair value of our commodity futures contracts are based on inputs that are quoted prices in active markets for identical assets or liabilities, resulting in Level 1 categorization of such measurements. The following table sets forth, by level within the fair value hierarchy, the fair value of our financial assets and liabilities at June 30, 2010 (in thousands):

	Quoted Prices in Active Markets for Identical Instruments (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value
Derivatives asset	$	39		—		—	$	39
Derivatives liability		1,108		—		—		1,108

Derivatives asset reflects the fair value of forward foreign exchange contracts entered into to hedge the exposure to fluctuations in currency values.

Derivatives liability reflects the fair value of natural gas swaps associated with the marketing of LNG and natural gas.

The estimated fair value of financial instruments, including those financial instruments for which the fair value option was not elected are set forth in the table below. The carrying amounts reported on our Consolidated Balance Sheets for cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, interest receivable, and accounts payable approximate fair value due to their short-term nature.

Financial Instruments (in thousands):

	June 30, 2010				December 31, 2009
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2013 Notes (1)	$	550,000	$	495,000	$	550,000	$	503,250
2016 Notes, net of discount (1)		1,635,376		1,365,539		1,633,029		1,371,744
Convertible Senior Unsecured Notes, net of discount (2)		171,942		102,305		165,132		95,777
2007 Term Loan (3)		298,000		287,992		400,000		384,640
2008 Convertible Loans (3)		247,563		249,569		293,714		299,001

(1)	The fair value of the Senior Notes, net of discount, is based on quotations obtained from broker-dealers who made markets in these and similar instruments as of June 30, 2010 and December 31, 2009, as applicable.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

(2)	The fair value of our Convertible Senior Unsecured Notes was based on the closing trading prices on June 30, 2010 and December 31, 2009, as applicable.

(3)

The 2007 Term Loan and 2008 Convertible Loans are closely held by few holders and purchases and sales are infrequent and are conducted on a bilateral basis without price discovery by us. These loans are not rated and have unique covenants and collateral packages such that comparisons to other instruments would be imprecise. Moreover, the 2008 Convertible Loans are convertible into shares of Cheniere common stock. Nonetheless, we have provided an estimate of the fair value of these loans as of June 30, 2010 and December 31, 2009 based on an index of the yield to maturity of CCC rated debt of other companies in the energy sector.

NOTE 11—Income Taxes

We are not presently a taxpayer and have not recorded a net liability for international, federal or state income taxes in any of the periods included in the accompanying financial statements. Our Consolidated Statements of Operations for the three and six-month periods ended June 30, 2010 and 2009 include no income tax benefits.

During the fourth quarter of 2008, largely due to the increased level of trading activity in our shares, we experienced an ownership change within the provisions of Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended, that will subject approximately $600 million of our existing net operating loss (“NOL”) carryforwards to the annual NOL utilization limitations. The applicable Section 382 limitation may affect our ability to fully utilize our existing tax NOL carryforwards. Our ability to fully utilize our existing tax NOL carryforwards is dependent on increasing the recognition of built-in gains in the five-year period following the above-referenced ownership change.

NOTE 12—Net Income (Loss) Per Share Attributable to Common Stockholders

Basic net income (loss) per share attributable to common stockholders (“EPS”) excludes dilution and is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted EPS reflects potential dilution and is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of common shares outstanding during the period increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued.

The following table reconciles basic and diluted weighted average common shares outstanding for the three and six-month periods ended June 30, 2010 and 2009 (in thousands except for loss per share):

	Three Months Ended June 30,					Six Months Ended June 30,
	2010		2009			2010		2009
Weighted average common shares outstanding:
Basic		55,317		51,576			55,161		50,121
Dilutive common stock options (1)		5,990		—			5,937		—
Dilutive Convertible Senior Unsecured Notes (2)		5,777		—			—		—
Dilutive 2008 Convertible Loans (3)		49,512		—			49,512		—
Diluted		116,596		51,576			110,610		50,121

Basic income (loss) per share attributable to common stockholders	$	1.55	$	(0.25	)	$	0.92	$	(1.91	)
Diluted income (loss) per share attributable to common stockholders	$	0.86	$	(0.25	)	$	0.62	$	(1.91	)

(1)

Stock options, phantom stock and unvested stock of 10.7 million shares representing securities that could potentially dilute basic EPS in the future, were not included in the diluted net loss per share computations for the three and six-month periods ended June 30, 2009, because they would have been anti-dilutive.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

(2)

Common shares of 5.8 million issuable upon conversion of the Convertible Senior Unsecured Notes for the three-month period ended June 30, 2009 were not included in the diluted computation because the computation of diluted net loss per share attributable to common stockholders utilizing the “if-converted” method would be anti-dilutive. Common shares of 5.8 million issuable upon conversion of the Convertible Senior Unsecured Notes for the six-month period ended June 30, 2009, were not included in the diluted computations because the computations of diluted net income (loss) per share attributable to common stockholders utilizing the “if-converted” method would be anti-dilutive.

(3)

Common shares of 50.0 million issuable upon conversion of the 2008 Convertible Loans were not included in the computations of diluted net loss per share for the three- and six-month periods ended June 30, 2009 because the computations of diluted net loss per share attributable to common stockholders utilizing the “if-converted” method would be anti-dilutive.

NOTE 13—Comprehensive Loss

The following table is a reconciliation of our net income (loss) attributable to common stockholders to our comprehensive income (loss) for the three and six-month periods ended June 30, 2010 and 2009 (in thousands):

	Three Months Ended June 30,							Six Months Ended June 30,
	2010			2009				2010			2009
Net income (loss) attributable to common stockholders	$	85,677			$	(13,051	)	$	50,510			$	(95,792	)
Other comprehensive income (loss) items:
Foreign currency translation		(82	)			104			(70	)			42
Comprehensive income (loss) attributable to common stockholders	$	85,595			$	(12,947	)	$	50,440			$	(95,750	)

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

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

	Six Months Ended June 30,
	2010		2009
Cash paid for interest, net of amounts capitalized	$	156,898	$	89,378
Construction-in-process and debt issuance additions funded with accrued liabilities		—		20,989

NOTE 15—Business Segment Information

We have three operating business segments: LNG receiving terminal business, natural gas pipeline business and LNG and natural gas marketing business. These operating 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 business segment consists of the operational Sabine Pass LNG receiving terminal, approximately 90.6% owned (at June 30, 2010) in western Cameron Parish, Louisiana on the Sabine Pass Channel and two other LNG receiving terminals that are in various stages of development at the following locations: 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.

Our natural gas pipeline business segment consists of the Creole Trail Pipeline, consisting of 94 miles of natural gas pipeline connecting the Sabine Pass LNG receiving terminal to numerous interconnection points with existing interstate natural gas pipelines in southwest Louisiana, and other natural gas pipelines in various stages of development to provide access to North American natural gas markets.

Our LNG and natural gas marketing business segment is seeking to develop a portfolio of long-term, short-term, and spot LNG purchase agreements and focuses on entering into business relationships for the domestic marketing of natural gas that is imported by Cheniere Marketing as LNG to the Sabine Pass LNG receiving terminal.

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):

	Segments
	LNG Receiving Terminal			Natural Gas Pipeline			LNG & Natural Gas Marketing			Corporate and Other (1)			Total Consolidation
As of or for the Six Months Ended June 30, 2010
Revenues	$	133,164		$	37		$	13,170		$	1,421		$	147,792
Intersegment revenues (losses) (2) (3) (4) (5)		127,710			255			(126,736	)		(1,229	)		—
Depreciation, depletion and amortization		21,363			7,496			572			1,805			31,236
Non-cash compensation		844			254			3,601			5,286			9,985
Income (loss) from operations		200,533			(10,848	)		(125,279	)		(8,669	)		55,737
Interest expense, net		(92,360	)		(22,394	)		—			(19,391	)		(134,145	)
Interest income		162			—			44			33			239
Goodwill		76,819			—			—			—			76,819
Total assets		1,920,528			561,737			94,771			30,445			2,607,481
Expenditures for additions to long-lived assets		1,937			(105	)		(349	)		(76	)		1,407

As of or for the Six Months Ended June 30, 2009
Revenues	$	38,201		$	75		$	(656	)	$	1,573		$	39,193
Intersegment revenues (losses) (2) (3) (4) (5)		126,614			431			(121,683	)		(5,362	)		—
Depreciation, depletion and amortization		14,017			7,436			731			2,673			24,857
Non-cash compensation		767			246			2,467			5,153			8,633
Income (loss) from operations		123,078			(10,886	)		(131,546	)		(17,722	)		(37,076	)
Interest expense, net		(70,946	)		(22,287	)		—			(21,976	)		(115,209	)
Interest income		937			—			181			81			1,199
Goodwill		76,844			—			—			—			76,844
Total assets		2,074,757			584,630			144,835			(18,437	)		2,785,785
Expenditures for additions to long-lived assets		89,583			910			69			241			90,803

For the Three Months Ended June 30, 2010
Revenues	$	66,337		$	26		$	1,028		$	884		$	68,275
Intersegment revenues (losses) (2) (3) (4) (5)		63,759			24			(63,058	)		(725	)		—
Depreciation, depletion and amortization		10,674			3,728			264			946			15,612
Non-cash compensation		376			121			1,040			2,098			3,635
Income (loss) from operations		101,850			(5,497	)		(67,091	)		(4,572	)		24,690
Interest expense, net		(45,922	)		(11,260	)		—			(9,768	)		(66,950	)
Interest income		96			—			30			16			142
Expenditures for additions to long-lived assets		917			60			(349	)		(12	)		616

For the Three Months Ended June 30, 2009
Revenues	$	38,201		$	75		$	(1,156	)	$	839		$	37,959
Intersegment revenues (losses) (2) (3) (4) (5)		64,065			161			(57,229	)		(6,997	)		—
Depreciation, depletion and amortization		7,262			3,768			362			1,403			12,795
Non-cash compensation		306			163			1,333			2,884			4,686
Income (loss) from operations		80,780			(4,728	)		(63,125	)		(12,605	)		322
Interest expense, net		(35,971	)		(11,288	)		—			(14,700	)		(61,959	)
Interest income		305			—			69			14			388
Expenditures for additions to long-lived assets		35,471			841			69			203			36,584

(1)

Includes corporate activities, oil and gas exploration, development and exploitation activities and certain intercompany eliminations. Our oil and gas exploration, development and exploitation operating activities have been included in the corporate and other column due to the lack of a material impact that these activities have on our consolidated financial statements.

(2)

Intersegment revenues related to our LNG receiving terminal segment are primarily from TUA capacity reservation fee revenues of $125.5 million and $125.1 million and tug revenues that were received from our LNG and natural gas marketing segment for the six months ended June 30, 2010 and 2009, respectively. Intersegment revenues related to our LNG receiving terminal

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(unaudited)

segment are primarily from TUA capacity reservation fee revenues of $62.8 million and $62.5 million and tug revenues that were received from our LNG and natural gas marketing segment for the three-month periods ended June 30, 2010 and 2009, respectively. These LNG receiving terminal segment intersegment revenues are eliminated with intersegment expenses in our Consolidated Statement of Operations.

(3)

Intersegment revenues related to our natural gas pipeline segment are primarily from transportation fees charged by our natural gas pipeline segment to our LNG receiving terminal and LNG and natural gas marketing segments to transport natural gas that was regasified at the Sabine Pass LNG receiving terminal. These natural gas pipeline segment intersegment revenues are eliminated with intersegment expenses in our Consolidated Statement of Operations.

(4)

Intersegment losses related to our LNG and natural gas marketing segment are primarily from TUA capacity reservation fee expenses of $125.5 million and $125.1 million and tug costs that were incurred from our LNG receiving terminal segment for the six-month periods ended June 30, 2010 and 2009, respectively. Intersegment losses related to our LNG and natural gas marketing segment are primarily from TUA capacity reservation fee expenses of $62.8 million and $62.5 million and tug costs that were incurred from our LNG receiving terminal segment for the three-month periods ended June 30, 2010 and 2009, respectively. The costs of the LNG and natural gas marketing segment TUA capacity reservation fee expenses are classified as marketing trading gains (losses) as they are considered capacity contracts related to our energy trading and risk management activities. These LNG and natural gas marketing segment intersegment revenues are eliminated with intersegment expenses in our Consolidated Statement of Operations.

(5)

Intersegment losses related to corporate and other are from various transactions between our LNG receiving terminal, natural gas pipeline and LNG and natural gas marketing segments in which revenue recorded by one operating segment is eliminated with a non-revenue line item (i.e. operating expense or is capitalized) by the other operating segment.

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”). We recognize our share-based payments to employees in the consolidated financial statements based on their fair values at the date of grant. The calculated fair value is recognized as expense (net of any capitalization) over the requisite service period, net of estimated forfeitures, using the straight-line method.

For the three and six months ended June 30, 2010, the total share-based compensation expense recognized in our net income attributable to common stockholders, net of capitalization was $3.6 million and $9.9 million, respectively. For the three and six months ended June 30, 2009, the total share-based compensation expense recognized in our net loss attributable to common stockholders, net of capitalization was $4.7 million and $8.6 million, respectively.

The total unrecognized compensation cost at June 30, 2010 relating to non-vested share-based compensation arrangements granted under the 1997 Plan and 2003 Plan, before any capitalization, was $15.9 million. The total unrecognized compensation cost at June 30, 2010 is expected to be recognized over 3.25 years, with a weighted average period of 0.8 years.

We received no proceeds from the exercise of stock options in the three and six-month periods ended June 30, 2010 and 2009.

ITEM 2.

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

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

•

statements relating to the construction or operation of each of our proposed liquefied natural gas (“LNG”) receiving terminals or our proposed pipelines or liquefaction facilities, 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 future levels of domestic natural gas production, supply or consumption; future levels of LNG imports into North America; sales of natural gas in North America; exports of natural gas from North America; and the transportation, other infrastructure or prices related to natural gas, LNG or other energy sources or hydrocarbon products;

•

statements regarding any financing transactions or arrangements, or ability to enter into such transactions or arrangements, whether on the part of Cheniere or at the project level;

•

statements regarding any terminal use agreement (“TUA”) or other commercial arrangements presently contracted, optioned or marketed, or potential arrangements, to be 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 LNG regasification or liquefaction 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, including potential revenues and capital expenditures, 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 such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “potential,” “project,” “propose,” “strategy” and similar terms. 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,” “the Company,” “we,” “our” and “us” refer to Cheniere Energy, Inc. and its wholly-owned or controlled subsidiaries.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed under “Risk Factors” in our current report on Form 8-K dated as of the date of this quarterly report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our consolidated financial statements and the accompanying notes in Item 1. “Consolidated Financial Statements.” This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future.

Our discussion and analysis includes the following subjects:

• Overview of Business

• Overview of Significant 2010 Events

• Liquidity and Capital Resources

• Results of Operations

• Off-Balance Sheet Arrangements

• Summary of Critical Accounting Policies and Estimates

• Recent Accounting Standards

Overview of Business

We own and operate the Sabine Pass LNG receiving terminal in Louisiana through our 90.6% ownership interest in and management agreements with Cheniere Energy Partners, L.P. (“Cheniere Partners”), which is a publicly traded partnership we created in 2007. We also own and operate the Creole Trail Pipeline, which interconnects the Sabine Pass LNG receiving terminal with downstream markets. One of our subsidiaries, Cheniere Marketing, LLC (“Cheniere Marketing”), is marketing liquefied natural gas (“LNG”) and natural gas and is developing a portfolio of contracts to monetize capacity at the Sabine Pass LNG receiving terminal and the Creole Trail Pipeline. We are also in various stages of developing other LNG receiving terminal and pipeline related projects, which, among other things, will require commercial justification before we make a final investment decision. In addition, we are engaged to a limited extent in oil and natural gas exploration and development activities in the Gulf of Mexico.

In June 2010, Cheniere Marketing assigned its TUA with Sabine Pass LNG, L.P. (“Sabine Pass”) to Cheniere Energy Investments, LLC (“Investments”), a wholly-owned subsidiary of Cheniere Partners, and concurrently Cheniere Marketing entered into a Variable Capacity Rights Agreement (“VCRA”) with Investments that allows Cheniere Marketing to continue to monetize the capacity at the Sabine Pass LNG receiving terminal on Investments’ behalf. The impact of this TUA assignment and VCRA on us is discussed throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations. The following diagram depicts our abridged organizational structure after the TUA assignment:

Overview of Significant 2010 Events

In the first six months of 2010, and through the date of this Form 10-Q, we continue to execute our strategy to operate and to monetize our capacity at the Sabine Pass LNG receiving terminal and the Creole Trail pipeline, as well as restructure our financial obligations, including the following:

In March 2010, Cheniere Marketing entered into various agreements (“JPMorgan LNG Agreements”) with JPMorgan LNG Co. (“LNGCo”), an indirect subsidiary of JPMorgan Chase & Co., providing Cheniere Marketing with financial support to source more cargoes of LNG than it could source on a stand-alone basis;

·	In June 2010, we used $102.0 million of cash received from the sale of our 30% limited partner interest in Freeport LNG Development, L.P. (“Freeport LNG”) to prepay a portion of the 2007 Term Loan described below;

In June 2010, we used $63.6 million of cash and cash equivalents held in a TUA reserve account established in connection with the 2008 Convertible Loans described below to prepay $60.9 million of accrued interest on, and $2.7 million of principal of, the 2008 Convertible Loans as a result of the assignment of the Cheniere Marketing TUA; and

In June 2010, Cheniere Partners initiated a project to add liquefaction services at the Sabine Pass LNG receiving terminal that would transform the terminal into a bi-directional facility capable of liquefying natural gas and exporting LNG in addition to importing and regasifying foreign-sourced LNG.

Liquidity and Capital Resources

Although results are consolidated for financial reporting, Cheniere, Sabine Pass LNG and Cheniere Partners operate with independent capital structures. Since the inception of both Sabine Pass LNG and Cheniere Partners, the cash needs of each entity have been met with a combination of borrowings, issuance of units and operating cash flows. We expect the cash needs for Sabine Pass LNG and Cheniere Partners over the next 12 months will be met through operating cash flows and existing unrestricted cash. With respect to Cheniere, we have historically satisfied cash needs by utilizing existing unrestricted cash, management fees from Sabine Pass LNG and Cheniere Partners, distributions from our investment in Cheniere Partners, distributions from our 30% investment in Freeport LNG and operating cash flows from our pipeline and LNG and natural gas marketing businesses. Below is a table (in thousands) that presents unrestricted and restricted cash for each portion of our capital structure as of June 30, 2010:

	Sabine Pass LNG, L.P.		Cheniere Energy Partners, L.P.		Other Cheniere Energy, Inc.		Consolidated Cheniere Energy, Inc.
Cash and cash equivalents	$	—	$	—	$	73,940	$	73,940
Restricted cash and cash equivalents		113,087		43,117		2,852		159,056
Total	$	113,087	$	43,117	$	76,792	$	232,996

As of June 30, 2010, we had unrestricted cash and cash equivalents of $73.9 million and accounts receivable and other working capital from LNG and natural gas marketing activities of approximately $28 million that will be available to Cheniere, which excludes cash and cash equivalents available to Cheniere Energy Partners, L.P. (“Cheniere Partners”), a publicly traded partnership in which we own a 90.6% interest, and Sabine Pass LNG, L.P. (“Sabine Pass LNG”), a wholly-owned subsidiary of Cheniere Partners. In addition, we had restricted cash and cash equivalents of $159.1 million, which were designated for the following purposes: $17.0 million for Sabine Pass LNG’s working capital; $43.1 million for Cheniere Partners’ working capital; $96.1 million for interest payments related to the Senior Notes described below; and $2.9 million for other restricted purposes. We believe that we have sufficient cash, other working capital and cash generated from our operations to fund our operating expenses and other cash requirements until the earliest date when principal payments may be required on our outstanding indebtedness. The lenders of the 2008 Convertible Loans can require prepayment of the loans between August 16, 2011 and September 14, 2011. If the lenders of the 2008 Convertible Loans do not require the principal prepayment in 2011, the earliest date that principal payments will be required is May 31, 2012, which is the maturity date of the 2007 Term Loan. Before our first required principal payment, we will need to restructure our finances and improve our capital structure, which may be accomplished by entering into long-term TUAs or LNG purchase agreements, refinancing our existing indebtedness, issuing equity or other securities, selling assets or a combination of the foregoing.

In the first six months of 2010, we have accomplished the following items that we believe improve our liquidity and strengthen our capital structure:

In March 2010, our liquidity position was improved by entering into the JPMorgan LNG Agreements, which monetized our then-existing LNG inventory of 2,415,000 MMBtu, may reduce our working capital requirements to operate our marketing business by allowing us to source more cargos of LNG than we could source on a stand-alone basis, and

may provide additional financial support to commercialize our capacity at the Sabine Pass LNG receiving terminal and Creole Trail Pipeline;

In May 2010, our capital structure was improved by the pre-payment of $102.0 million of principal of the 2007 Term Loan as a result of the sale of our 30% interest in Freeport LNG. The principal pre-payment also reduced the amount of annual interest payable under the 2007 Term Loan by $10.1 million, offsetting or potentially exceeding any distributions we may have received from our 30% interest in Freeport LNG as a source of liquidity; and

In June 2010, our liquidity and capital structure were improved by assigning Cheniere Marketing’s TUA to a subsidiary of Cheniere Partners and entering into related transactions. We used the restricted cash that was previously reserved to fund Cheniere Marketing’s TUA payment obligation to prepay $60.9 million in accrued interest and $2.7 million of principal on the 2008 Convertible Loans. As a result of the TUA assignment and related transactions, we improved our annual cash flow by $5 million to $16 million on a net basis:

o	the assignment of the TUA eliminated the need for us to use distributions we receive from Cheniere Partners to fund Cheniere Marketing’s TUA payment obligation and therefore the distributions we receive will be available to us as unrestricted cash;

o	the elimination of Cheniere Marketing’s TUA payments reduces the cash available to Cheniere Partners to make distributions on the subordinated units that we own; and

we amended our management services agreement with Cheniere Partners to change our fixed management fee to a variable fee dependent on cash available to Cheniere Partners after distributions to its common unitholders and general partner and therefore the cash we receive for managing Cheniere Partners may be less than it was prior to June 30, 2010.

Our ability to continue enhancing near-term liquidity and improving our capital structure is dependent on numerous factors, including the availability of credit, changes in worldwide and domestic supply and demand for natural gas and LNG, and the relative prices for natural gas in North America and international markets. We face numerous financial, market and operational risks in connection with improving our liquidity situation, many of which are beyond our control.

LNG Receiving Terminal Business

Cheniere Partners

Our ownership interest in the Sabine Pass LNG receiving terminal is held through Cheniere Partners. In 2007, Cheniere Partners completed a public offering. As a result of this public offering, our combined general partner and limited partner ownership interests in Cheniere Partners was reduced to approximately 90.6% (we hold 135,383,831 subordinated units, 10,891,357 common units and 3,302,045 general partner units of Cheniere Partners). Cheniere Partners owns a 100% interest in Sabine Pass LNG, which is operating the Sabine Pass LNG receiving terminal.

We receive quarterly distributions from Cheniere Partners for our ownership interests. For the six month period ended June 30, 2010, we received $9.3 million in distributions from our common units, $115.1 million from our subordinated units and $2.8 million from our general partner interests. Cheniere Partners relies on the receipt of operating revenues from Sabine Pass LNG’s TUAs to fund quarterly cash distributions to us and other unitholders. Sabine Pass LNG is not permitted under the indenture governing the Senior Notes (the “Sabine Pass Indenture”) to make cash distributions to Cheniere Partners if it does not satisfy a fixed charge coverage ratio test of 2:1, calculated as required in the Sabine Pass Indenture, as well as other conditions. If the coverage test is not met, we may not receive distributions.

In June 2010 Cheniere Marketing assigned its existing TUA with Sabine Pass LNG to Investments, including all of its rights, titles, interests, obligations and liabilities in and under the TUA and will therefore no longer be obligated to make the approximately $250 million per year of payments to Sabine Pass LNG; however, Cheniere Marketing has agreed to pay for certain taxes and regulatory costs during the term of the VCRA. In connection with the assignment, Cheniere’s guarantee of Cheniere Marketing’s obligations under the TUA was terminated and Cheniere Partners provided a guarantee of Investments’ obligations under the TUA. Investments is required to make capacity payments aggregating approximately $250 million per year through at least September 30, 2028. As a result of the assignment of the TUA, Cheniere Partners will have adequate available cash to make distributions on our subordinated units only to the extent it generates additional cash flow.

Concurrent with the TUA assignment, Investments entered into the variable capacity rights agreement (“VCRA”) with Cheniere Marketing. The VCRA will continue until the earliest of (a) the termination of Investments’ TUA, (b) the expiration of the

initial term of the TUA, (c) the termination of the VCRA by either party after two years, and (d) the termination of the VCRA as a result of default. Under the terms of the VCRA, Cheniere Marketing will continue to be responsible for monetizing the capacity at the Sabine Pass LNG receiving terminal and will have the right to utilize all of the services and other rights at the Sabine Pass LNG receiving terminal available under the TUA assigned to Investments. In consideration of these rights, Cheniere Marketing is obligated to pay Investments 80% of the expected gross margin of each cargo of LNG it arranges for delivery to the Sabine Pass LNG receiving terminal. To the extent payments from Cheniere Marketing to Investments under the VCRA increase Cheniere Partners’ available cash in excess of the common unit and general partner distributions and certain reserves, the cash would be distributed to us in the form of distributions on our subordinated units. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs under the TUA. We have guaranteed all of Cheniere Marketing’s payment obligations under the VCRA.

We also receive payments from Sabine Pass LNG and Cheniere Partners for management services that we provide. We received $9.3 million of management and service fees from Sabine Pass LNG and Cheniere Partners pursuant to existing agreements for the six-month period ended June 30, 2010. In June 2010, we and Cheniere Partners amended, effective as of July 1, 2010, the fee structure for the various general and administrative services provided by us for Cheniere Partners’ benefit and changed it from a fixed fee to a variable fee. The amended and restated services agreement provides that fees will be paid quarterly from Cheniere Partners’ unrestricted cash and cash equivalents remaining after making distributions to the common unitholders and the general partner in respect of each quarter and retaining certain reserves. Our ability to receive management fees from Cheniere Partners is dependent on our ability to, among other things, manage Cheniere Partners’ and Sabine Pass LNG’s operating and administrative expenses, monetize the 2.0 billion cubic feet per day (“Bcf/d”) regasification capacity held by Investments (as discussed below) and develop new projects through either internal development or acquisition to increase cash flow.

Sabine Pass LNG Receiving Terminal

The entire approximately 4.0 Bcf/d of regasification capacity at the Sabine Pass LNG receiving terminal has been fully reserved under three 20-year, firm commitment TUAs. 2.0 Bcf/d is contracted with unaffiliated third parties and 2.0 Bcf/d is contracted with Investments. Each of the three 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. Capacity reservation fee TUA payments are made by Sabine Pass LNG’s third-party customers as follows:

•

Total Gas and Power North America, Inc. (formerly known as Total LNG USA, Inc.) (“Total”) has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions; and

•

Chevron U.S.A., Inc. (“Chevron”) has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced on July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

In June 2010, Sabine Pass LNG entered into amendments of the TUAs with Total and Chevron for the purpose of clarifying various operational rights and obligations of the parties. In connection with these amendments, Total and Chevron have agreed to minimum pro rata inventory obligations as necessary to ensure cryogenic readiness of the Sabine Pass LNG receiving terminal and to mitigate the effects of inventory weathering. In addition, Total and Chevron have each agreed to daily boil-off gas re-delivery obligations, service fees related to the compression services associated with minimization of their respective daily boil-off gas re-delivery obligations and pro-rata obligations for the incremental fuel associated with these compression services. Additional items clarified in these amendments include the recognition of inventory transfers between parties and procedural obligations related to daily and monthly informational postings, gas re-delivery and vessel nominations and delivery point flexibility.

Each of Total and Chevron previously paid Sabine Pass LNG $20.0 million in nonrefundable advance capacity reservation fees, which are being amortized over a 10-year period as a reduction of each customer’s regasification capacity reservation fees payable under its respective TUA.

In November 2006, Cheniere Marketing reserved approximately 2.0 Bcf/d of regasification capacity under a TUA and was required to make capacity payments aggregating approximately $250 million per year for the period from January 1, 2009, through at least September 30, 2028. Cheniere guaranteed Cheniere Marketing’s obligations under its TUA.

In June 2010, Cheniere Marketing assigned its TUA with Sabine Pass LNG to Investments, including all of its rights, titles, interests, obligations and liabilities in and under the TUA and will therefore no longer be obligated to make the approximately $250 million per year of payments to Sabine Pass LNG. In connection with the assignment, Cheniere’s guarantee of Cheniere Marketing’s obligations under the TUA was terminated and Cheniere Partners provided a guarantee of Investments’ obligations under the TUA.

Investments is required to make capacity payments aggregating approximately $250 million per year through at least September 30, 2028; however, the revenue earned by Sabine Pass LNG and the capacity payments under the TUA will be eliminated upon consolidation of our financial statements.

Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered for the customer’s account, which Sabine Pass LNG will use primarily as fuel for revaporization and self-generated power at the Sabine Pass LNG receiving terminal.

Other LNG Receiving Terminals

As discussed above, in May 2010, we sold our 30% limited partnership interest in Freeport LNG. However, prior to the sale, Freeport LNG made aggregate distributions to us of $24.0 million since inception.

We will contemplate making final investment decisions to construct our Corpus Christi and Creole Trail LNG receiving terminal projects upon, among other things, entering into acceptable commercial and financing arrangements for the applicable project. We do not expect to spend significant funds on these projects in the near-term.

Liquefaction Project

As mentioned above, in June 2010, Cheniere Partners initiated a project to add liquefaction services at the Sabine Pass LNG receiving terminal that would transform the terminal into a bi-directional facility capable of liquefying natural gas and exporting LNG in addition to importing and regasifying foreign-sourced LNG. As currently contemplated, the liquefaction project would be designed and permitted for up to four modular LNG trains, each with a peak processing capacity of up to approximately 0.7 Bcf/d of natural gas and an average liquefaction capacity of approximately 3.5 million tons per annum (“mtpa”). The initial project phase is anticipated to include two modular trains and the capacity to process on average approximately 1.2 Bcf/d of pipeline quality natural gas. Cheniere Partners believes that the time and cost required to develop its proposed liquefaction project would be materially lessened by Sabine Pass LNG’s existing large acreage and infrastructure (docks, LNG storage tanks, power generation assets and pipeline connections). Development costs incurred during the assessment of this project will be funded by Cheniere Partners using its existing funds. Cheniere Partners will contemplate making a final investment decision to commence construction of the liquefaction facility upon, among other things, achieving regulatory approval and entering into acceptable commercial and financing arrangements. We anticipate LNG export could commence as early as 2015.

Natural Gas Pipeline Business

Phase 1 of the Creole Trail Pipeline, consisting of 94 miles of natural gas pipeline, had been constructed and is currently in-service and operating .

We will contemplate making a final investment decision to construct Phase 2 of the Creole Trail Pipeline, the Corpus Christi Pipeline, the Cheniere Southern Trail Pipeline and the Burgos Hub Project upon, among other things, receiving all required authorizations to construct and operate the applicable pipeline (and storage facility in the case of Burgos Hub), to the extent not already obtained, and entering into acceptable commercial and financing arrangements for the applicable project. We do not expect to spend significant funds on these projects in the near-term.

As discussed above, we believe that we have sufficient cash, other working capital and cash generated from our operations to operate Phase 1 of our Creole Trail Pipeline until the earliest date when principal payments on our outstanding indebtedness may be required. The lenders of the 2008 Convertible Loans can require prepayment of the loans between August 16, 2011 and September 14, 2011. If the lenders of the 2008 Convertible Loans do not require the principal payment in 2011, the earliest date that principal payments will be required is May 31, 2012, which is the maturity date of the 2007 Term Loan.

LNG and Natural Gas Marketing Business

In June 2010, as discussed above, Cheniere Marketing assigned its TUA to Investments and concurrently entered into a VCRA with Investments in order for Investments to monetize its capacity at the Sabine Pass LNG receiving terminal. On a consolidated basis, the LNG and natural gas marketing earnings under the VCRA will be included on our Consolidated Statement of Operations under Marketing and trading revenue.

The accounting treatment for LNG inventory differs from the treatment for derivative positions such that the economics of Cheniere Marketing’s activities are not transparent in the consolidated financial statements until all LNG inventory is sold and all derivative positions are settled. Our LNG inventory is recorded as an asset at cost and is subject to lower of cost or market (“LCM”) adjustments at the end of each reporting period. The LCM adjustment market price is based on period-end natural gas spot prices, and any gain or loss from a LCM adjustment is recorded in our earnings at the end of each period. Revenue and cost of goods sold are not

recognized in our earnings until the regasified LNG is sold. Our unrealized derivatives positions at the end of each period extend into the future to hedge the cash flow from future sales of our LNG inventory or to take market positions and hedge exposure associated with LNG and natural gas. These positions are measured at fair value, and we record the gains and losses from the change in their fair value currently in earnings. Thus, earnings from changes in the fair value of our derivatives may not be offset by losses from LCM adjustments to our LNG inventory because the LCM adjustments that may be made to LNG inventory are based on period-end spot prices that are different from the time periods of the prices used to fair value our derivatives. Any losses from changes in the fair value of our derivatives will not be offset by gains until the regasified LNG is actually sold.

Management evaluates the performance of its LNG and natural gas marketing business activities differently than the measure calculated and presented in accordance with GAAP in our Consolidated Statements of Operations. Management calculates an Adjusted LNG and natural gas revenue non-GAAP measure to assess the performance of the LNG and natural gas marketing business activities during each period. As our LNG and natural gas marketing business has entered into natural gas swaps that hedge the cash flows from the future sale of LNG inventory and to take market positions and hedge exposure associated with LNG and natural gas, management believes that the presentation of the Adjusted LNG and natural gas revenue non-GAAP measure provides a meaningful indicator of the performance of our LNG and natural gas marketing business activities during the stated period.

The table below shows the differences between the components of both the LNG and natural gas marketing revenue GAAP measure (presented in our Consolidated Statement of Operations) and the Adjusted LNG and natural gas revenue non-GAAP measure (in thousands):

	For the Six Months Ended June 30, 2010
	LNG and natural gas marketing revenue (GAAP measure)			Adjusted LNG and natural gas marketing revenue (Non-GAAP measure)			Difference

Physical natural gas sales	$	36,485		$	36,485		$	—
Cost of LNG		(29,762	)		(41,261	)		11,499	(a)
Realized natural gas derivative gain		4,298			4,298			—
Unrealized gas derivative gain		(41	)		(41	)		—
Other energy trading activities and adjustments		2,190			1,661			529
LNG and natural gas revenue	$	13,170		$	1,142		$	12,028

(a)

The Cost of LNG GAAP measure takes into consideration only the cost of LNG that was regasified and sold during the six-month period ended June 30, 2010, using the weighted average cost method for LNG inventory. The Cost of LNG non-GAAP measure represents the marketing revenue, net of historical cost of LNG, expected from future LNG inventory sales based on published forward natural gas price curve prices corresponding to the future months when the regasified LNG is planned to be sold.

Under GAAP measurement, our LNG and natural gas marketing revenue was $13.2 million for the six-month period ended June 30, 2010, but only $1.1 million was generated by marketing activities during the period. We believe that the adjusted LNG and natural gas marketing revenue non-GAAP measure is a meaningful indicator of performance of our LNG and natural gas marketing business activities during a stated period.

JPMorgan LNG Agreements

In March 2010, Cheniere Marketing entered into the JPMorgan LNG Agreements with LNGCo under which Cheniere Marketing has agreed to develop and maintain commercial and trading opportunities in the LNG industry and present any such opportunities exclusively to LNGCo. Cheniere Marketing also agreed to provide, or arrange for the provision of, all of the operations and administrative services required by LNGCo in connection with any LNG cargoes purchased by LNGCo, including negotiating agreements and transporting, receiving, storing, hedging and regasifying LNG cargoes. Cheniere Marketing does not have the authority to contractually bind LNGCo under the JPMorgan LNG Agreements. In the event LNGCo declines to purchase an LNG cargo presented to it by Cheniere Marketing under the JPMorgan LNG Agreements, Cheniere Marketing may pursue the opportunity on its own behalf or present it to third parties. The term of the JPMorgan LNG Agreements is two years; however, either party may terminate without penalty at the end of one year. In return for the services to be provided by Cheniere Marketing, LNGCo will pay a fixed fee to Cheniere Marketing and may pay additional fees dependent upon the gross margins of each transaction and the aggregate revenue earned during the term of the JPMorgan LNG Agreements.

represents our fixed fee receivable and is reported as Current Accounts and Interest Receivable, and the remaining portion is reported as Other Non-Current Assets and is to be paid to Cheniere Marketing upon the completion or termination of the LNGCo Agreements.

As discussed above, we believe that we have sufficient cash, other working capital and cash generated from our operations to fund our LNG and natural gas marketing business until the earliest date when principal payments on our outstanding indebtedness may be required. The lenders of the 2008 Convertible Loans can require prepayment of the loans between August 16, 2011 and September 14, 2011. If the lenders of the 2008 Convertible Loans do not require the principal payment in 2011, the earliest date that principal payments will be required is May 31, 2012, which is the maturity date of the 2007 Term Loan.

Corporate and Other Activities

We are required to maintain corporate general and administrative functions to serve our business activities described above. As discussed above, we believe that we have sufficient cash, other working capital and cash generated from our operations to fund our operating expenses and other cash requirements until the earliest date when principal payments on our outstanding indebtedness may be required. The lenders of the 2008 Convertible Loans can require prepayment of the loans between August 16, 2011 and September 14, 2011. If the lenders of the 2008 Convertible Loans do not require the principal payment in 2011, the earliest date that principal payments will be required is May 31, 2012, which is the maturity date of the 2007 Term Loan.

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 exploration activities in the shallow waters of the Gulf of Mexico. We do not anticipate significant cash expenditures related to these activities and expect our cash inflows from oil and natural gas production to decrease as reserves are produced.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash and cash equivalents for the six-month periods ended June 30, 2010 and 2009 (in thousands). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, that are referred to elsewhere in this report. Additional discussion of these items follows the table.

	Six Months Ended June 30,
	2010			2009
Sources of cash and cash equivalents
Proceeds from sale of limited partnership investment	$	104,330		$	—
Use of restricted cash and cash equivalents		20,894			149,479
Distribution from limited partnership investment in Freeport LNG		3,900			6,600
Other		326			4,286
Total sources of cash and cash equivalents		129,450			160,365

Uses of cash and cash equivalents
Debt repurchases		(104,681	)		(30,030	)
Operating cash flow		(20,604	)		(27,643	)
Distributions to non-controlling interest		(13,196	)		(13,196	)
LNG receiving terminal and pipeline construction-in-process, net		(3,065	)		(81,175	)
Purchases of LNG for commissioning, net of amounts transferred to LNG receiving terminal construction-in-process		—			(14,184	)
Other		(2,336	)		(7,383	)
Total uses of cash and cash equivalents		(143,882	)		(173,611	)

Net increase (decrease) in cash and cash equivalents		(14,432	)		(13,246	)
Cash and cash equivalents—beginning of period		88,372			102,192
Cash and cash equivalents—end of period	$	73,940		$	88,946

Proceeds from sale of limited partnership investment

In May 2010, we sold our 30% interest in Freeport LNG to institutional investors for net proceeds of $104.3 million.

Use of restricted cash and cash equivalents

In the six-month period ended June 30, 2010, the $20.9 million of restricted cash and cash equivalents were used primarily to make distributions of $13.2 million to non-controlling interests, repurchase debt of $2.7 million, pay for construction activities at the Sabine Pass LNG receiving terminal of $1.5 million and other items of $3.5 million.

In the six-month period ended June 30, 2009, the $149.5 million of restricted cash and cash equivalents were used primarily to pay for scheduled interest payments and construction activities at the Sabine Pass LNG receiving terminal. Under the Sabine Pass Indenture, a portion of the proceeds from the Senior Notes was initially required to be used for scheduled interest payments through May 2009 and to fund the cost to complete construction of the Sabine Pass LNG receiving terminal. Due to these restrictions imposed by the Sabine Pass Indenture, the proceeds from the Senior Notes are not presented as cash and cash equivalents. When proceeds from the Senior Notes that have been designated as restricted cash and cash equivalents are used, they are presented as a source of cash and cash equivalents. The decreased use of restricted cash and cash equivalents in the six-month period ended June 30, 2010, primarily resulted from substantially completing construction of the Sabine Pass LNG receiving terminal during the third quarter of 2009.

Distribution from limited partnership investment in Freeport LNG

In the six-month periods ended June 30, 2010 and 2009, we received $3.9 million and $6.6 million of distributions from our Freeport LNG. In June 2010, we sold our investment in Freeport LNG and therefore do not expect to receive distributions in the future.

Debt Repurchases

In the six-month periods ended June 30, 2010 and 2009, we used $104.7 million and $30.0 million of cash and cash equivalents to repurchase a portion of our long-term debt.

In the second quarter of 2010, we used $102.0 million of the net proceeds from the sale of our limited partner interest in Freeport LNG to partially prepay the 2007 Term Loan. In addition, as a result of the assignment of the Cheniere Marketing TUA in the second quarter of 2010, we used $2.7 million to partially prepay the 2008 Convertible Loans.

In the second quarter of 2009, we used a combination of $30.0 million cash and cash equivalents and 4.0 million common shares to prepay $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes.

Operating cash flow

In the six-month periods ended June 30, 2010 and 2009, we used $20.6 million and $27.6 million, respectively, of cash and cash equivalents for operating activities. Net cash used in operations related primarily to the general administrative overhead costs, pipeline operations costs, LNG and natural gas marketing overhead; offset by earnings from our LNG and natural gas marketing business.

Distributions to non-controlling interest

In the six-month periods ended June 30, 2010 and 2009, Cheniere Partners distributed $13.2 million to its non-affiliated common unitholders.

LNG receiving terminal and pipeline construction-in-process, net

In the six-month periods ended June 30, 2010 and 2009, capital expenditures for our LNG receiving terminals and pipeline projects were $3.1 million and $81.2 million, respectively. Our capital expenditures decreased in the six-month period ended June 30, 2010 as a result of the achievement of full operability of the Sabine Pass LNG receiving terminal.

Purchases of LNG for commissioning, net of amounts transferred to LNG receiving terminal construction-in-process

During the six-month periods ended June 30, 2010 and 2009, we purchased zero and $14.2 million, respectively, for LNG commissioning cargoes, net of amounts transferred to LNG receiving terminal construction-in-process. As a result of achieving full operability of the Sabine Pass LNG receiving terminal in the third quarter of 2009, the purchases of LNG for commissioning, net decreased in the first six months of 2010.

Debt Agreements

The following table (in thousands) and the explanatory paragraphs following the table summarize our debt agreements as of June 30, 2010.

	Sabine Pass LNG, L.P.			Cheniere Energy Partners, L.P.		Other Cheniere Energy, Inc.			Consolidated Cheniere Energy, Inc.
Long-term debt (including related parties)
Senior Notes (including related parties)	$	2,215,500		$	—	$	—		$	2,215,500
2007 Term Loan		—			—		298,000			298,000
2008 Convertible Loans (including related parties)		—			—		247,563			247,563
Convertible Senior Unsecured Notes		—			—		204,630			204,630
Total long-term debt		2,215,500			—		750,193			2,965,693

Debt discount (including related parties)
Senior Notes (including related parties) (1)		(30,124	)		—		—			(30,124	)
Convertible Senior Unsecured Notes (2)		—			—		(32,688	)		(32,688	)
Total debt discount		(30,124	)		—		(32,688	)		(62,812	)
Long-term debt (including related parties), net of discount	$	2,185,376		$	—	$	717,505		$	2,902,881

(1)

In September 2008, Sabine Pass LNG issued an additional $183.5 million, par value, of 2016 Notes. The net proceeds from the additional issuance of the 2016 Notes were $145.0 million. The difference between the par value and the net proceeds is the debt discount, which will be amortized through the maturity of the 2016 Notes.

(2)

Effective as of January 1, 2009, we are required to record a debt discount on our Convertible Senior Unsecured Notes. The unamortized discount will be amortized through the maturity of the Convertible Senior Unsecured Notes.

Convertible Senior Unsecured Notes

In July 2005, we consummated a private offering of $325.0 million aggregate principal amount of Convertible Senior Unsecured Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The notes bear interest at a rate of 2¼% per year. Interest on the notes is payable semi-annually in arrears on February 1 and August 1 of each 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 June 30, 2010, 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 securities rate plus 50 basis points. The indenture governing the notes contains customary reporting requirements.

As discussed in Note 9—“Long-Term Debt and Long-Term Debt—Related Parties” of our Notes to Consolidated Financial Statements, we adopted on January 1, 2009 an accounting standard that requires issuers of certain convertible debt instruments to separately account for the liability component and the equity component represented by the embedded conversion option in a manner that will reflect that entity’s nonconvertible debt borrowing rate when interest costs are recognized in subsequent periods. The fair value of the embedded conversion option at the date of issuance of the Convertible Senior Unsecured Notes was determined to be $134.0 million and has been recorded as a debt discount to the Convertible Senior Unsecured Notes, with a corresponding adjustment to Additional Paid-in Capital. At June 30, 2010, the unamortized debt discount to the Convertible Senior Unsecured Notes was $32.7 million.

Sabine Pass LNG Senior Notes

Sabine Pass LNG has issued an aggregate principal amount of $2,215.5 million of Senior Notes consisting of $550.0 million of 7¼% Senior Secured Notes due 2013 and $1,665.5 million of 7½% Senior Secured Notes due 2016. Interest on the Senior Notes is payable semi-annually in arrears on May 30 and November 30 of each year. The Senior Notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG’s equity interests and substantially all of its operating assets. Under the Sabine Pass Indenture governing the Senior Notes, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment of $82.4 million. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass Indenture.

2007 Term Loan

In May 2007, Cheniere Subsidiary Holdings, LLC, a 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 9¾% 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. The 2007 Term Loan will mature on May 31, 2012. The 2007 Term Loan is secured by a pledge of our 135,383,831 subordinated units in Cheniere Partners.

In May 2010, we sold our 30% interest in Freeport LNG to institutional investors for net proceeds of $104.3 million. The net proceeds from the sale were used to prepay $102.0 million of the 2007 Term Loan in May 2010 (see Note 7—“Investment in Limited Partnership” for additional information). As of June 30, 2010 and December 31, 2009, $298.0 million and $400.0 million, respectively, were outstanding under the 2007 Term Loan and were included in Long-term Debt on our Consolidated Balance Sheets.

2008 Convertible Loans

In August 2008, we entered into a credit agreement pursuant to which we obtained $250.0 million in convertible term loans (“2008 Convertible Loans”). The 2008 Convertible Loans will mature in 2018, but the lenders can require prepayment of the loans for thirty days following August 15, 2011, 2013 and 2015, and upon a change of control. The 2008 Convertible Loans bear interest at a fixed rate of 12% per annum, except during the occurrence of an event of default during which time the rate of interest will be 14% per annum. Interest is due semi-annually on the last business day of January and July. At our option, until August 15, 2011, accrued interest may be added to the principal on each semi-annual interest date. The aggregate amount of all accrued interest to August 15, 2011 will be payable on the maturity date. The 2008 Convertible Loans are secured by Cheniere’s rights and fees payable under management services agreements with Sabine Pass LNG and Cheniere Partners, by Cheniere’s 10.9 million common units in Cheniere Partners, by the equity and non-real property assets of Cheniere’s pipeline entities, by the equity of various other subsidiaries and certain other assets and subsidiary guarantees. The principal amount of $250.0 million may be exchanged for newly-created Series B Convertible Preferred Stock, par value $0.0001 per share (“Series B Preferred Stock”), with voting rights limited to the equivalent of 10,125,000 shares of common stock. The exchange ratio is one share of Series B Preferred Stock for each $5,000 of outstanding borrowings, subject to adjustment. The exchange ratio will be adjusted in the event we make certain distributions of cash, shares or property on our shares of common stock. The aggregate Series B Preferred Stock is exchangeable into 50 million shares of common stock at a price of $5.00 per share pursuant to a broadly syndicated offering. We are required to file a registration statement to register the Series B Preferred Stock upon demand by the majority of the holders of the Series B Preferred Stock. Such holders also have the right to demand registration of the shares of common stock into which the Series B Preferred Stock is convertible. No portion of any accrued interest is eligible for conversion into Series B Preferred Stock.

As long as the 2008 Convertible Loans are exchangeable for shares of Series B Preferred Stock or shares of Series B Preferred Stock remain outstanding, the holders of a majority of the 2008 Convertible Loans and Series B Preferred Stock, acting together, have the right to nominate two individuals to the Company’s Board of Directors, and together with the Board of Directors, a third nominee, who would be an independent director. In addition, one of the lenders is Scorpion Capital Partners LP (“Scorpion”), an affiliate of one of the Company’s directors.

In June 2010, we amended the 2008 Convertible Loans permit all funds on deposit in a TUA reserve account to be applied to the prepayment of the accrued interest outstanding under the 2008 Convertible Loans, with any remainder to be applied to the prepayment of the principal balance of the 2008 Convertible Loans. As a result, $63.6 million from the TUA Reserve Account was used to prepay $60.9 million of accrued interest and $2.7 million of principal.

Issuances of Common Stock

In the six-month periods ended June 30, 2010 and 2009, no shares of our common stock were issued pursuant to the exercise of stock options. In the six-month periods ended June 30, 2010 and 2009, we issued 382,000 shares and 314,000 shares, respectively, of non-vested restricted stock to new and existing employees. In the six month period ended June 30, 2009, we issued 4.0 million shares of our common stock as part of the consideration used to repurchase a portion of the Convertible Senior Unsecured Notes.

Results of Operations

Three-Month Period Ended June 30, 2010 vs. Three-Month Period Ended June 30, 2009

Overall Operations

Our consolidated net income (loss) attributable to common stockholders increased $98.8 million, from a net loss of ($13.1) million, or ($0.25) per share (basic and diluted), in the three-month period ended June 30, 2009 to a net income of $85.7 million, or $1.55 per share basic and $0.86 per share diluted, in the three-month period ended June 30, 2010. This increase was primarily due to a gain on the sale of our 30% interest in Freeport LNG and increased LNG receiving terminal revenues as a result of the Sabine Pass LNG receiving terminal starting commercial operations during 2009, which were partially offset by increased LNG receiving terminal and pipeline operating expenses, increased depreciation, depletion and amortization expense (“DD&A”), increased general and administrative expenses and increased interest expense, net.

Gain on Sale of Equity Method Investment

In May 2010, we sold our 30% interest in Freeport LNG and recognized a net $128.3 million gain. The gain was comprised of net proceeds received of $104.3 million, and $24.0 million of distributions in excess of income.

LNG Receiving Terminal Revenue

Revenues increased $27.8 million, from $38.2 million in the three-month period ended June 30, 2009 to $66.0 million in the three-month period ended June 30, 2010. This increase primarily resulted from the commencement of services under the Chevron TUA beginning on July 1, 2009.

LNG and Natural Gas Marketing Revenue

Operating results from marketing and trading activities are presented on a net basis on our Consolidated Statements of Operations. Marketing and trading revenues represent the margin earned on the purchase and transportation costs of LNG and subsequent sales of natural gas to third parties. Our marketing and trading revenues also include pretax derivative gains/losses and inventory lower-of-cost-or-market adjustments, if any. See table below (in thousands) for itemized comparison of each major type of energy trading and risk management activity:

	Three Month Period Ended June 30,
	2010			2009
Physical natural gas sales, net of costs and inventory write-down	$	929		$	(1,061	)
Loss from derivatives		(2,104	)		(219	)
Other energy trading activities		2,204			124
Total LNG and natural gas marketing gain (loss)	$	1,029		$	(1,156	)

Marketing and trading revenues increased $2.2 million, from a ($1.2) million loss in the three-month period ended June 30, 2009 to a gain of $1.0 million in the three-month period ended June 30, 2010. The $1.0 million gain in the three-month period ended June 30, 2010 primarily resulted from $3.1 million other energy trading activities partially offset by ($2.1) million in derivative loss. The increase in natural gas marketing and trading revenue is primarily a result of the different marketing and trading activities we were engaged in during the three-month period ended June 30, 2010 including our agreements with LNGCo that became effective April 1, 2010, compared to the same period of 2009 during which we began purchasing, transporting and unloading commercial LNG cargoes into the Sabine Pass LNG receiving terminal and used certain hedging strategies to maximize margins on these cargoes. The ($1.2) million loss in the three-month period ended June 30, 2009 primarily resulted from lower of cost or market write-downs to our inventory.

LNG Receiving Terminal and Pipeline Operating Expense

Our LNG receiving terminal and pipeline operating expenses include costs incurred to operate the Sabine Pass LNG receiving terminal and the Creole Trail Pipeline.

Operating and maintenance expense increased $0.5 million, from $9.3 million in the three-month period ended June 30, 2009, to $9.8 million in the three-month period ended June 30, 2010. This increase primarily resulted from the achievement of full operability of the Sabine Pass LNG receiving terminal with approximately 4.0 Bcf/d of total sendout capacity and five LNG storage tanks with approximately 16.9 Bcf of aggregate storage capacity in the third quarter of 2009.

DD&A

DD&A increased $2.8 million, from $12.8 million in the three-month period ended June 30, 2009, to $15.6 million in the three-month period ended June 30, 2010. This increase resulted from beginning to depreciate the costs associated with achieving full operability of the Sabine Pass LNG receiving terminal in the third quarter of 2009.

Interest Expense, net

Interest expense, net of amounts capitalized, increased $5.0 million, from $62.0 million in the three-month period ended June 30, 2009 to $67.0 million in the three-month period ended June 30, 2010. This increase in interest expense resulted from the achievement of full operability of the Sabine Pass LNG receiving terminal in the third quarter of 2009, which reduced the amount of interest expense that could be capitalized.

Six-Month Period Ended June 30, 2010 vs. Six-Month Period Ended June 30, 2009

Overall Operations

Our consolidated net income (loss) attributable to common stockholders increased $146.3 million, from a net loss of ($95.8) million, or ($1.91) per share (basic and diluted), in the six-month period ended June 30, 2009 to net income of $50.5 million, or $0.92 per share basic and $0.62 per share diluted, in the six-month period ended June 30, 2010. This increase was primarily due to a gain on the sale of our 30% interest in Freeport LNG and increased LNG receiving terminal revenues as a result of the Sabine Pass LNG receiving terminal starting commercial operations during 2009 which was partially offset by increased LNG receiving terminal and pipeline operating expenses, increased depreciation, depletion and amortization expense (“DD&A”), increased general and administrative expenses and increased interest expense, net.

Gain on Sale of Equity Method Investment

LNG Receiving Terminal Revenue

Revenues increased $95.0 million, from $38.2 in the six-month period ended June 30, 2009 to $133.2 million in the six-month period ended June 30, 2010. This increase primarily resulted from the commencement of services under the Total TUA beginning on April 1, 2009 and the Chevron TUA beginning on July 1, 2009.

LNG and Natural Gas Marketing Revenue

subsequent sales of natural gas to third parties. Our marketing and trading revenues also include pretax derivative gains/losses and inventory lower-of-cost-or-market adjustments, if any. See table below (in thousands) for itemized comparison of each major type of energy trading and risk management activity:

	Six-Month Period Ended June 30,
	2010		2009
Physical natural gas sales, net of costs	$	6,724	$	(1,062	)
Gain (loss) from derivatives		4,256		(219	)
Other energy trading activities		2,190		625
Total LNG and natural gas marketing gain (loss)	$	13,170	$	(656	)

Marketing and trading revenues increased $13.9 million, from ($0.7) million in the six-month period ended June 30, 2009 to $13.2 million in the six-month period ended June 30, 2010. The $13.9 million increase in the six-month period ended June 30, 2010 primarily resulted from $6.7 million of net revenue from physical sales of LNG, $4.3 million in derivative gains and $2.2 million of other energy trading activities. The increase in natural gas marketing and trading revenue is primarily a result of the different marketing and trading activities we were engaged in during the six-month period ended June 30, 2010 including our agreements with LNGCo that became effective April 1, 2010, compared to the same period of 2009 during which we began purchasing, transporting and unloading commercial LNG cargoes into the Sabine Pass LNG receiving terminal and used certain hedging strategies to maximize margins on these cargoes. The $(0.7) million loss in the six-month period ended June 30, 2009 primarily resulted from lower of cost or market write-downs to our inventory.

LNG Receiving Terminal and Pipeline Operating Expense

Our LNG receiving terminal and pipeline operating expenses include costs incurred to operate the Sabine Pass LNG receiving terminal and the Creole Trail Pipeline.

Operating and maintenance expense increased $4.6 million, from $18.0 million in the six-month period ended June 30, 2009, to $22.6 million in the six-month period ended June 30, 2010. This increase primarily resulted from the achievement of full operability of the Sabine Pass LNG receiving terminal with approximately 4.0 Bcf/d of total sendout capacity and five LNG storage tanks with approximately 16.9 Bcf of aggregate storage capacity in the third quarter of 2009.

DD&A

DD&A increased $6.3 million, from $24.9 million in the six-month period ended June 30, 2009, to $31.2 million in the six-month period ended June 30, 2010. This increase resulted from beginning to depreciate the costs associated with achieving full operability of the Sabine Pass LNG receiving terminal in the third quarter of 2009.

Interest Expense, net

Interest expense, net of amounts capitalized, increased $18.9 million, from $115.2 million in the six-month period ended June 30, 2009 to $134.1 million in the six-month period ended June 30, 2010. This increase in interest expense resulted from the achievement of full operability of the Sabine Pass LNG receiving terminal, which reduced the amount of interest expense that was capitalized.

Off-Balance Sheet Arrangements

We entered into agreements with LNGCo to provide Cheniere Marketing with financial support to source more cargoes of LNG than it could source on a stand-alone basis. See Note 4—“Variable Interest Entity” and “Management’s Discussion and Analysis – Liquidity and Capital Resources—LNG and Natural Gas Marketing Business” for further information related to our variable interest in LNGCo. As of June 30, 2010, Cheniere Marketing’s maximum exposure to loss relating to LNGCo was $3.0 million, related to margin deposits that have been paid to LNGCo and fixed fee and gross margin revenue receivables that have been earned as of June 30, 2010. A portion of this $3.0 million represents our fixed fee receivable and is reported as Current Accounts and Interest Receivable, and the remaining portion is reported as Other Non-Current Assets and is to be paid to Cheniere Marketing upon the completion or termination of the LNGCo Agreements.

Summary of Critical Accounting Policies and Estimates

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 apply the accounting rules to the specific set of circumstances existing in our business. In preparing our consolidated financial statements in conformity with GAAP, we endeavor 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 and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as intangible LNG assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.

We capitalize interest and other related debt costs during the construction period of our LNG receiving terminal. Upon commencement of operations, capitalized interest, as a component of the total cost, will be amortized over the estimated useful life of the asset.

Revenue Recognition

LNG regasification capacity reservation fees are recognized as revenue over the term of the respective TUAs. Advance capacity reservation fees are initially deferred and amortized over a 10-year period as a reduction of a customer’s regasification capacity reservation fees payable under its TUA. The retained 2% of LNG delivered for each customer’s account at the Sabine Pass LNG receiving terminal is recognized as revenues as Sabine Pass LNG performs the services set forth in each customer’s TUA.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Actual results could differ from the estimates and assumptions used.

Estimates used in the assessment of impairment of our long-lived assets, including goodwill, are the most significant of our estimates. There are numerous uncertainties inherent in estimating future cash flows of assets or business segments. The accuracy of any cash flow estimate is a function of judgment used in determining the amount of cash flows generated. As a result, cash flows may be different from the cash flows that we use to assess impairment of our assets. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Significant negative industry or economic trends, including a significant decline in the market price of our common stock, reduced estimates of future cash flows for our business segments or disruptions to our business could lead to an impairment charge of our long-lived assets, including goodwill and other intangible assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment of our long-lived assets, including goodwill, we may be required to record a charge to earnings in our consolidated financial statements during a period in which such impairment is determined to exist, which may negatively impact our results of operations.

Other items subject to estimates and assumptions include asset retirement obligations, valuation allowances for net deferred tax assets, valuations of derivative instruments, valuations of noncash compensation and collectability of accounts receivable and other assets.

As future events and their effects cannot be determined accurately, actual results could differ significantly from our estimates.

LNG and Natural Gas Marketing

We have determined that our LNG and natural gas marketing business activities are energy trading and risk management activities for trading purposes and have elected to present these activities on a net basis on our Consolidated Statements of Operations. Marketing and trading revenues represent the margin earned on the purchase and transportation of LNG purchases and subsequent sales of natural gas to third parties. These energy trading and risk management activities include, but are not limited to: purchase of LNG and natural gas, transportation contracts, and derivatives. Below is a brief description of our accounting treatment of each type of energy trading and risk management activity and how we account for it:

Purchase of LNG and natural gas

The purchase value of LNG or natural gas inventory is recorded as an asset on our Consolidated Balance Sheets at the cost to acquire the product. Our inventory is subject to lower of cost or market adjustment each quarter. Recoveries of losses resulting from interim period lower of cost or market adjustments are made due to market price recoveries on the same inventory in the same fiscal year and are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. Any adjustment to our inventory is recorded on a net basis as LNG and natural gas marketing revenue on our Consolidated Statements of Operations.

Transportation contracts

We enter into transportation contracts with respect to the transport of LNG or natural gas to a specific location for storage or sale. Transportation costs that are incurred during the purchase of LNG or natural gas are capitalized as part of the acquisition costs of the product. Transportation costs incurred to sell LNG or natural gas are recorded on a net basis as LNG and natural gas marketing revenue on our Consolidated Statements of Operations.

Derivatives

We use derivative instruments from time to time to hedge the cash flow variability of our commodity trading activities. We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 10—“Financial Instruments” of our Notes to Consolidated Financial Statements. We record changes in the fair value of our derivative positions in our LNG and natural gas marketing revenue on our Consolidated Statements of Operations based on the value for which the derivative instrument could be exchanged between willing parties. To date, all of our derivative positions fair value determinations have been made by management using quoted prices in active markets for identical instruments. The ultimate fair value of our derivative instruments is uncertain, and we believe that it is possible that a change in the estimated fair value will occur in the near future as commodity prices change.

Regulated Natural Gas Pipelines

Our 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. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in the Consolidated Balance Sheets as Other Assets and Other Liabilities. We periodically evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write-off the associated regulatory assets and liabilities.

Items that may influence our assessment are:

•

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

•

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

•

excess capacity;

•

increased competition and discounting in the markets we serve; and

•

impacts of ongoing regulatory initiatives in the natural gas industry.

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

Goodwill

Goodwill represents the excess of cost over fair value of the assets of businesses acquired. It is evaluated annually for impairment by first comparing our management’s estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. We had goodwill of $76.8 million at June 30, 2010 and December 31, 2009, attributable to our LNG receiving terminal segment.

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. As discussed above regarding our use of estimates, our judgments and assumptions are inherent in our management’s estimate of future cash flows used to determine the estimate of the reporting unit’s fair value. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.

Share-Based Compensation Expense

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, using the Black-Scholes-Merton option valuation model. We recognize share-based compensation net of an estimated forfeiture rate and only recognize compensation cost for those shares expected to vest on a straight-line basis over the requisite service period of the award.

Determining the appropriate fair value model and calculating the fair value of share-based payment awards requires the use of highly subjective assumptions, including the expected life of the share-based payment awards and stock price volatility. We believe that implied volatility, calculated based on traded options of our common stock, combined with historical volatility is an appropriate indicator of expected volatility and future stock price trends. Therefore, the expected volatility for the year ended December 31, 2009 used in our fair value model was based on a combination of implied and historical volatilities. The assumptions used in calculating the fair value of share-based payment awards represent our best estimates, but these estimates involve inherent uncertainties and the application of management judgment. As a result, if factors change and we use different assumptions, our share-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, future share-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).

Recent Accounting Standards

In June 2009, the Financial Accounting Standards Board (“FASB”) issued an amendment to the accounting and disclosure requirements for the consolidation of variable interest entities. This guidance affects the overall consolidation analysis and requires enhanced disclosures on involvement with variable interest entities. The guidance is effective as of the first annual reporting period beginning after November 15, 2009, for interim periods within the first annual reporting period and thereafter. Our adoption of this authoritative guidance had no impact on our financial position, results of operations or cash flow.

In January 2010, the FASB issued authoritative guidance which requires additional disclosures and clarifies certain existing disclosure requirements regarding fair value measurements. This guidance is effective for interim and annual reporting periods beginning after December 15, 2009. We adopted this guidance effective January 1, 2010. However, none of the specific additional disclosure requirements were applicable to us at the time of filing this report. See Note 10—“Financial Instruments” for our fair value measurement disclosures.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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.

Marketing and Trading Commodity Price Risk

Through Cheniere Marketing, from time to time we will enter into natural gas and foreign currency derivatives to hedge the exposure of future cash flows associated with the LNG that we hold. We use value at risk (“VaR”) and other methodologies for market risk measurement and control purposes. The VaR is calculated using the Monte Carlo simulation method. At June 30, 2010 and December 31, 2009, the one-day VaR with a 95% confidence interval on our derivative positions were $0.4 million and less than $0.1 million, respectively.

Our derivative positions as of June 30, 2010 primarily consisted of financial derivatives to take market positions associated with LNG and natural gas. As of June 30, 2010, we had entered into a total equivalent of 1,012,500 million British thermal units (“MMBtu”) of natural gas swaps through January 2011 for which we will receive fixed prices of $4.324 to $7.151 per MMBtu. At June 30, 2010, the value of the natural gas swaps was a liability of $1.1 million.

Our derivative positions as of June 30, 2010 also consisted of forward foreign exchange contracts entered into to hedge exposure associated with our LNG and natural gas market positions. As of June 30, 2010, we had entered into forward contracts through August 2010 to exchange a total of 3,250,000 GBP for which we would receive fixed exchange rates of 1.455 to 1.546 USD/GBP

Item 4.

Disclosure Controls and Procedures

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

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

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of June 30, 2010, 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.

Item 1A.

Risk Factors

We have updated our Risk Factors in a Current Report on Form 8-K dated as of the date of this quarterly report, which are incorporated herein by reference.

Item 6.

Exhibits


10.1*	Termination Agreement, dated June 24, 2010, by and among Sabine Pass LNG, L.P., Cheniere Marketing, LLC and JPMorgan LNG Co.

10.2*	Amendment of LNG Terminal Use Agreement, dated June 15, 2010, by and between Total Gas & Power North America, Inc. and Sabine Pass LNG, L.P.

10.3*	Amendment of LNG Terminal Use Agreement, dated June 16, 2010, by and between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P.

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

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

32.1**	Certification 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

*	Filed herewith.

**	Furnished herewith.

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/ JERRY D. SMITH

Jerry D. Smith

Vice President and Chief Accounting Officer

(on behalf of the registrant and

as principal accounting officer)

Date: August 5, 2010