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statements relating to the construction or operation of each of our proposed liquefied natural gas ("LNG") terminals or our proposed pipelines, liquefaction facilities or other projects, 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, transportation, liquefaction and storage capacity, the number of storage tanks, LNG trains, docks, pipeline deliverability and the number of pipeline interconnections, if any;

•	statements that we expect to receive an order from the Federal Energy Regulatory Commission ("FERC") authorizing us to construct and operate proposed LNG receiving terminals, liquefaction facilities, pipelines or other projects by certain dates, or at all;

•	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 or other markets; exports of LNG 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 or refinancing transactions or arrangements, or ability to enter into such transactions or arrangements, whether on the part of Cheniere or any subsidiary or at the project level;

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statements regarding any 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, liquefaction or storage capacity that are, or may become, subject to such commercial arrangements;

•	statements regarding counterparties to our commercial contracts, 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.

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•	Bcf means billion cubic feet;

•	Bcf/d means billion cubic feet per day;

•	EPC means engineering, procurement and construction;

•	LNG means liquefied natural gas;

•	LNG train means an independent modular unit for gas liquefaction;

•	MMBtu means million British thermal units;

•	Mtpa means million metric tons per annum; and

•	TUA means terminal use agreement.

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•	safely maintaining and operating the Sabine Pass LNG terminal and the Creole Trail Pipeline;

•	obtaining the requisite regulatory permits and financing to reach a final investment decision on Cheniere Partners' liquefaction project;

•	expanding the Sabine Pass LNG terminal to add liquefaction capabilities, and modifying the Creole Trail Pipeline to transport natural gas to the Sabine Pass LNG terminal for fuel and for Sabine Pass Liquefaction to satisfy its LNG delivery obligations under its SPAs;

•	contracting for feed and fuel gas for Cheniere Partners' liquefaction project;

•	utilizing the 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal held by one of Cheniere Partners' wholly owned subsidiaries, Cheniere Energy Investments, LLC ("Cheniere Investments"), for short-term and spot LNG purchases and sales until such capacity is used in connection with Cheniere Partners' liquefaction project;

•	developing business relationships for the marketing of additional long-term and short- term agreements for excess LNG volumes at the Sabine Pass LNG terminal that have not been sold to our long-term customers, and for long-term and short-term contracts for potential future projects at other sites; and

•	optimizing our capital structure to finance the construction and operation of the facilities needed to serve our customers.

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•	LNG terminal business;

•	natural gas pipeline business; and

•	LNG and natural gas marketing business.

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•	Total has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated 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 has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

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BG Gulf Coast LNG, LLC ("BG") has agreed to purchase 286.5 million MMBtu of LNG per year (approximately 5.5 mtpa) for a fixed sales charge of (i) $2.25 per MMBtu for 182.5 million MMBtu commencing upon the date of first commercial delivery for LNG train 1, (ii) $3.00 per MMBtu for 36.5 million MMBtu commencing upon the date of first commercial delivery for LNG train 2 (the "Train 2 Tranche"), (iii) $3.00 per MMBtu for 34.0 million MMBtu commencing upon the date of first commercial delivery for LNG train 3 (the "Train 3 Tranche") and (iv) $3.00 per MMBtu for 33.5 million MMBtu commencing upon the date of first commercial delivery for LNG train 4 (the "Train 4 Tranche"), plus in each case a contract sales price for each MMBtu of LNG delivered under the SPA equal to 115% of the final settlement price for the New York Mercantile Exchange Henry Hub natural gas futures contract for the month in which the relevant cargo is scheduled. The fixed sales charge is equivalent to approximately $411 million, $520 million, $622 million and $723 million per year upon completion of LNG trains 1, 2, 3 and 4, respectively, such that after completion of LNG train 4, the fixed sales charge will be a total of approximately $723 million per year;

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Gas Natural Aprovisionamientos SDG S.A. ("Gas Natural Fenosa"), an affiliate of Gas Natural SDG S.A., has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa) for a fixed sales charge of $2.49 per MMBtu for the full contract quantity, plus a contract sales price for each MMBtu of LNG delivered under the SPA equal to 115% of the final settlement price for the New York Mercantile Exchange Henry Hub natural gas futures contract for the month in which the relevant cargo is scheduled. The fixed sales charge is equivalent to approximately $454 million per year, commencing upon the date of first commercial delivery for LNG train 2;

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Korea Gas Corporation ("KOGAS") has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa) for a contract sales price equal to $3.00 plus 115% of the final settlement price for the New York Mercantile Exchange Henry Hub natural gas futures contract for the month in which the relevant cargo is scheduled. The fixed portion of the contract sales price is equivalent to approximately $548 million per year, commencing upon the date of first commercial delivery for LNG train 3; and

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GAIL (India) Limited ("GAIL") has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa) for a contract sales price equal to $3.00 plus 115% of the final settlement price for the New York Mercantile Exchange Henry Hub natural gas futures contract for the month in which the relevant cargo is scheduled. The fixed portion of the contract sales price is equivalent to approximately $548 million per year, commencing upon the date of first commercial delivery for LNG train 4. Prior to the commencement of LNG train 4 operations, GAIL will purchase 10.4 million MMBtu of LNG per year (approximately 0.2 mtpa) commencing upon the date LNG train 2 becomes commercially operable.

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if Bechtel fails to timely commence the work, abandons the work, fails to materially comply with its material obligations, makes an unpermitted assignment, fails to maintain required insurance, materially disregards applicable law or applicable standards and codes, or an insolvency event occurs with respect to Bechtel or its guarantor, then Sabine Pass Liquefaction will have the right to require that Bechtel cure such default, and if Bechtel fails to cure such default, or if Bechtel or its guarantor experiences an insolvency event, Sabine Pass Liquefaction may terminate the EPC Contract;

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Sabine Pass Liquefaction has the right to terminate the EPC Contract for its convenience, in which case Bechtel will be paid the portion of the Contract Price for the work performed, costs reasonably incurred by Bechtel on account of such termination and demobilization, and a lump sum of between $1.0 million and $2.5 million depending on the termination date if the EPC Contract is terminated prior to issuance of the notice to proceed and up to $30.0 million depending on the termination date if the EPC Contract is terminated after issuance of the notice to proceed;

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if Sabine Pass Liquefaction fails to pay any undisputed amount, fails to materially comply with any of its material obligations, or experiences an insolvency event, then Bechtel has the right to provide written notice demanding that such default be cured, and if Sabine Pass Liquefaction fails to cure such default or Sabine Pass Liquefaction experiences an insolvency event, Bechtel may terminate the EPC Contract;

•	if one force majeure event causes suspension of a substantial portion of the work for more than 100 consecutive days or any one or more force majeure events causes suspension of a substantial portion of the work for a period exceeding 180 days in the aggregate during any continuous 24-month period, then either party may terminate the EPC Contract; or

•	if Sabine Pass Liquefaction fails to issue the notice to proceed by December 31, 2012, then either party may terminate the EPC Contract, and Bechtel will be paid costs reasonably incurred by Bechtel on account of such termination and a lump sum of $5.0 million.

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•	rates and charges for natural gas transportation and related services;

•	the certification and construction of new facilities;

•	the extension and abandonment of services and facilities;

•	the maintenance of accounts and records;

•	the acquisition and disposition of facilities;

•	the initiation and discontinuation of services; and

•	various other matters.

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•	large, multinational and national companies with longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources;

•	oil and gas producers who sell or control LNG derived from their international oil and gas properties; and

•	purchasers located in other countries where prevailing market prices can be substantially different from those in the U.S.

•	major integrated marketers who have large amounts of capital to support their marketing operations and offer a full-range of services and market numerous products other than natural gas;

•	producer marketers who sell their own natural gas production or the production of their affiliated natural gas production company;

•	small geographically focused marketers who focus on marketing natural gas for the geographic area in which their affiliated distributor operates; and

•	aggregators who gather small volumes of natural gas from various sources, combine them and sell the larger volumes for more favorable prices and terms than would be possible selling the smaller volumes separately.

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•	Risks Relating to Our Financial Matters;

•	Risks Relating to Our LNG Terminal Business;

•	Risks Relating to Our Natural Gas Pipeline Business;

•	Risks Relating to Our LNG and Natural Gas Marketing Business;

•	Risks Relating to Our LNG Businesses in General; and

•	Risks Relating to Our Business in General.

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•	an operating account has been funded with amounts sufficient to cover the succeeding 45 days of operating and maintenance expenses, maintenance capital expenditures and obligations, if any, under an assumption agreement and a state tax sharing agreement;

•	one-sixth of the amount of interest due on the Senior Notes on the next interest payment date (plus any shortfall from any such month subsequent to the preceding interest payment date) has been transferred to a debt payment account;

•	outstanding principal on the Senior Notes then due and payable has been paid;

•	taxes payable by Sabine Pass LNG or the guarantors of the Senior Notes and permitted payments in respect of taxes have been paid; and

•	the debt service reserve account has on deposit the amount required to make the next interest payment on the Senior Notes.

•	a default for 30 days in the payment of interest on the Senior Notes;

•	a failure to pay any principal of the Senior Notes;

•	a failure by Sabine Pass LNG to comply with various covenants in the Sabine Pass Indenture;

•	a failure to observe any other agreement in the Sabine Pass Indenture beyond any specified cure periods;

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•	a default under any mortgage, indenture or instrument governing any indebtedness for borrowed money by Sabine Pass LNG in excess of $25.0 million if such default results from a failure to pay principal or interest on, or results in the acceleration of, such indebtedness;

•	a final money judgment or decree (not covered by insurance) in excess of $25.0 million is not discharged or stayed within 60 days following entry;

•	a failure of any material representation or warranty in the security documents entered into in connection with the Sabine Pass Indenture to be correct;

•	the Sabine Pass LNG terminal project is abandoned; or

•	certain events of bankruptcy or insolvency.

•	make certain investments;

•	purchase, redeem or retire equity interests;

•	issue preferred stock;

•	sell or transfer assets;

•	incur liens;

•	enter into transactions with affiliates;

•	consolidate, merge, sell or lease all or substantially all of its assets; and

•	enter into sale and leaseback transactions.

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•	performing below expected levels of efficiency;

•	breakdown or failures of equipment or systems;

•	operational errors by vessel or tug operators or others;

•	operational errors by us or any contracted facility operator or others;

•	labor disputes; and

•	weather-related interruptions of operations.

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•	the issuance and/or continued availability of necessary permits, licenses and approvals from governmental agencies and third parties as are required to construct and operate liquefaction facilities;

•	the availability of sufficient financing on reasonable terms, or at all;

•	our ability to satisfy the conditions precedent in SPAs with customers by specified dates;

•	our ability to meet the conditions precedent in our construction contract with Bechtel by December 31, 2012 in order to commence construction of the first two LNG trains;

•	our ability to enter into additional satisfactory agreements with contractors and to maintain good relationships with these contractors in order to construct the proposed liquefaction facilities within the expected cost parameters, and the ability of those contractors to perform their obligations under the contracts and to maintain their creditworthiness;

•	local and general economic conditions;

•	catastrophes, such as explosions, fires and product spills;

•	resistance in the local community to the project to add liquefaction capabilities at the Sabine Pass LNG terminal;

•	labor disputes; and

•	weather conditions, such as hurricanes.

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•	design and engineer Cheniere Partners' proposed LNG liquefaction facilities to operate in accordance with specifications;

•	engage and retain third-party subcontractors and procure equipment and supplies;

•	respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;

•	attract, develop and retain skilled personnel, including engineers;

•	post required construction bonds and comply with the terms thereof;

•	manage the construction process generally, including coordinating with other contractors and regulatory agencies; and

•	maintain their own financial condition, including adequate working capital.

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•	perform ongoing assessments of pipeline integrity;

•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•	improve data collection, integration and analysis;

•	repair and remediate the pipeline as necessary; and

•	implement preventative and mitigating actions.

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•	expected supply is less than the amount hedged;

•	the counterparty to the hedging contract defaults on its contractual obligations; or

•	there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

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•	relatively minor changes in the supply of, and demand for, natural gas in relevant markets;

•	political conditions in natural gas producing regions;

•	the extent of domestic production and importation of natural gas in relevant markets;

•	the level of demand for LNG and natural gas in relevant markets, including the effects of economic downturns or upturns;

•	weather conditions;

•	the competitive position of natural gas as a source of energy compared with other energy sources; and

•	the effect of government regulation on the production, transportation and sale of natural gas.

•	additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG from the Sabine Pass LNG terminal;

•	competitive liquefaction capacity in North America, which could divert natural gas from Cheniere Partners' proposed liquefaction facilities at our existing and proposed LNG terminals;

•	insufficient or oversupply of LNG liquefaction or receiving capacity worldwide;

•	insufficient LNG tanker capacity;

•	reduced demand and lower prices for natural gas;

•	increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

•	cost improvements that allow competitors to offer LNG regasification services or provide liquefaction capabilities at reduced prices;

•	changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;

•	changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;

•	adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and

•	cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

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•	increased construction costs;

•	economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;

•	decreases in the price of LNG and natural gas, which might decrease the expected returns relating to investments in LNG projects;

•	the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;

•	political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and

•	any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.

•	an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;

•	political or economic disturbances in the countries where the vessels are being constructed;

•	changes in governmental regulations or maritime self-regulatory organizations;

•	work stoppages or other labor disturbances at the shipyards;

•	bankruptcy or other financial crisis of shipbuilders;

•	quality or engineering problems;

•	weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and

•	shortages of or delays in the receipt of necessary construction materials.

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•	currency fluctuations;

•	war;

•	expropriation or nationalization of assets;

•	renegotiation or nullification of existing contracts;

•	changing political conditions;

•	changing laws and policies affecting trade, taxation and investment;

•	multiple taxation due to different tax structures; and

•	the general hazards associated with the assertion of sovereignty over certain areas in which operations are conducted.

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(1)	General and administrative expense includes $24.4 million, $16.1 million, $19.2 million, $55.0 million, and $56.6 million share-based compensation expense recognized in the years ended December 31, 2011, 2010, 2009, 2008, and 2007 respectively.

(2)	In the second quarter of 2008, we announced a cost savings program in connection with the downsizing of our natural gas marketing business activities, the nearing completion of significant construction activities for both the Sabine Pass LNG terminal and Creole Trail Pipeline and the seeking of alternative arrangements for our time charter interest in two LNG vessels.

(3)	In 2010, our investment in Freeport LNG Development, L.P. ("Freeport LNG") was sold, generating net cash proceeds of $104.3 million and a gain to Cheniere of $128.3 million.

(4)

Amount in 2010 relates to the cost to amend certain provisions of our 2008 Loans (described below under "Debt Agreements"). Amount in 2009 relates to gains on the termination of $120.4 million of our Convertible Senior Unsecured Notes.  Amount in 2008 relates to losses on the termination of a $95.0 million bridge loan in August 2008. See Note 15—"Debt and Debt—Related Parties" of our Notes to Consolidated Financial Statements.

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•	Overview of Business

•	Overview of Significant Events

•	Liquidity and Capital Resources

•	Contractual Obligations

•	Results of Operations

•	Off-Balance Sheet Arrangements

•	Inflation and Changing Prices

•	Summary of Critical Accounting Policies and Estimates

•	Recent Accounting Standards

•	In January 2011, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction") and Sabine Pass LNG, L.P. ("Sabine Pass LNG"), each a wholly owned subsidiary of Cheniere Partners, submitted an application to the FERC requesting authorization to site, construct and operate liquefaction and export facilities at the Sabine Pass LNG terminal.

•	In January 2011, Cheniere Partners initiated an at-the-market program to sell up to 1.0 million of its common units, the proceeds from which are being used for general business purposes, including to fund development costs associated with its liquefaction project. As of December 31, 2011, Cheniere Partners had sold 0.5 million common units with net proceeds of $9.0 million.

•	In May 2011, Sabine Pass Liquefaction received an order from the U.S. Department of Energy ("DOE") with authorization to export domestically produced natural gas from the Sabine Pass LNG terminal as LNG to any country that has, or in the future develops, the capacity to import LNG and with which trade is permissible.

•	In June 2011, we sold 12.7 million shares of Cheniere common stock in an underwritten public offering for net cash proceeds of $123.1 million.

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In September 2011, Cheniere Partners sold 3.0 million common units in an underwritten public offering and 1.1 million common units to Cheniere Common Units Holding, LLC, a wholly owned subsidiary of Cheniere, at a price of $15.25 per common unit. Cheniere Partners received net proceeds from this offering of approximately $60 million that it is using for general business purposes, including development costs of its project to add liquefaction capacity at the Sabine Pass LNG terminal.

•	In September 2011, we initiated an at-the-market program to sell up to 10.0 million shares of Cheniere common stock. As of December 31, 2011, we had sold 1.5 million shares with net proceeds of $14.4 million.

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In October 2011, Sabine Pass Liquefaction entered into its first LNG sale and purchase agreement ("SPA") with BG Gulf Coast LNG, LLC ("BG"), an affiliate of BG Energy Holdings Limited, under which BG agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa). This agreement was amended in January 2012 to increase the amount of LNG that BG has agreed to purchase to 286.5 million MMBtu of LNG per year (approximately 5.5 mtpa).

•	In November 2011, Sabine Pass Liquefaction entered into an SPA with Gas Natural Aprovisionamientos SDG S.A. ("Gas Natural Fenosa"), an affiliate of Gas Natural SDG S.A., under which Gas Natural Fenosa has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa).

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In November 2011, Sabine Pass Liquefaction entered into a lump sum turnkey engineering, procurement and construction ("EPC") agreement with Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") for the first two LNG trains and related facilities at the Sabine Pass LNG terminal. The agreement provides that Sabine Pass Liquefaction will pay Bechtel a contract price of $3.9 billion, which is subject to adjustment by change order.

•	In December 2011, Sabine Pass Liquefaction entered into an SPA with GAIL (India) Limited ("GAIL"), under which GAIL has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa). Prior to the commencement of LNG train 4 operations, GAIL will purchase bridge volumes of approximately 0.2 mtpa upon the commencement of operations of LNG train 2.

•	In December 2011, we sold 41.7 million shares of Cheniere common stock in an underwritten public offering for net cash proceeds of approximately $330.9 million.

•	In January 2012, we repaid in full the entire outstanding principal balance of the 2007 Term Loans due May 31, 2012. We used a portion of the net proceeds from the public offering of common stock in December 2011 to repay the 2007 Term Loan.

•	In January 2012, Sabine Pass Liquefaction entered into an SPA with Korea Gas Corporation ("KOGAS"), under which KOGAS agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa).

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(1)	All cash and cash equivalents presented above for Sabine Pass LNG are considered restricted to us, but $4.3 million is considered unrestricted for Sabine Pass LNG.

(2)	All cash and cash equivalents presented above for Cheniere Partners are considered restricted to us, but $81.4 million is considered unrestricted for Cheniere Partners, including the $4.3 million considered unrestricted for Sabine Pass LNG.

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•	Total Gas and Power North America, Inc. ("Total") has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated 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 is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

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(1)	In January 2012, we repaid the 2007 Term Loan in full.

(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.

(3)	In September 2008, Sabine Pass LNG issued an additional $183.5 million, par value, of 2016 Notes described below.  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.

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the excess of: a) the present value at such redemption date of (i) the redemption price of the Senior Notes plus (ii) all required interest payments due on the Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over b) the principal amount of the Senior Notes, if greater.

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(1)

Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2011, our cash payments for interest would be $212.2 million in 2012, $195.3 million in 2013, $158.8 million in 2014, $158.8 million in 2015 and $195.0 million for the remaining years for a total of $920.1 million.  See Note 15—"Debt and Debt—Related Parties" of our Notes to Consolidated Financial Statements.

(2)	A discussion of these obligations can be found at Note 7—"Leases" of our Notes to Consolidated Financial Statements.

(3)	Minimum lease payments have not been reduced by a minimum sublease rental of $3.4 million due in the future under non-cancelable subleases. A discussion of these sublease rental payments can be found at Note 7—"Leases" of our Notes to Consolidated Financial Statements.

(4)	A discussion of these obligations can be found at Note 20—"Commitments and Contingencies" of our Notes to Consolidated Financial Statements.

(5)	Includes obligations for cooperative endeavor agreements, LNG terminal security services, telecommunication services and software licensing.

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•	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.

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•	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.

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(1)

In March and April 2007, we and Cheniere Partners completed a public offering of 15,525,000 Cheniere Partners common units (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.

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(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 net proceeds 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.

(3)

Cash distributions to the non-controlling interest are recorded directly against the non-controlling interest on our Consolidated Balance Sheet. There is no obligation beyond what is reflected in our financial statements to fund or absorb such distributions to the non-controlling interest. If in the future the non-controlling interest on our Consolidated Balance Sheet is reduced to zero, these distributions may increase the loss allocated to us.

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(1)	Includes certain lease option renewals as they were reasonably assured.

(2)	Future annual minimum lease payments do not include $3.4 million expected to be recovered through sublease agreements for our office leases in Houston, Texas.

(3)	Lease payments for our tug boat lease represent third-party tug boat lease payment obligations and do not take into account the payments we receive from our third-party TUA customers that effectively offset $80.2 million, or two-thirds of our lease payment obligations, as discussed below.

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the excess of: a) the present value at such redemption date of (i) the redemption price of the Senior Notes plus (ii) all required interest payments due on the Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over b) the principal amount of the Senior Notes, if greater.

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(1)

LNG Inventory Derivatives asset is classified as other current assets on our Consolidated Balance Sheets. Changes in the fair value of LNG Inventory Derivatives are recorded in marketing and trading revenues on our Consolidated Statements of Operations. We recorded marketing and trading revenues of $2.5 million, $2.3 million and $8.6 million related to LNG Inventory Derivatives in the years ended December 31, 2011, 2010 and 2009, respectively.

(2)

Fuel Derivatives liability is classified as other current liabilities on our Consolidated Balance Sheets. Changes in the fair value of Fuel Derivatives are classified as derivative gain (loss) on our Consolidated Statements of Operations. We recorded derivative loss of $2.3 million and derivative gain of $0.5 million and $5.3 million in the years ended December 31, 2011, 2010 and 2009, respectively.

(1)	The estimated fair value of the Senior Notes, net of discount, was based on quotations obtained from broker-dealers who make markets in these and similar instruments.

(2)	The estimated fair value of our Convertible Senior Unsecured Notes was based on the closing trading prices on December 31, 2011 and 2010, as applicable.

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(3)

The 2007 Term Loan is closely held by few holders, and purchases and sales are infrequent and are conducted on a bilateral basis without price discovery by us.  This loan is not rated and has unique covenants and collateral packages such that comparisons to other instruments would be imprecise. Nonetheless, we have provided an estimate of the fair value of this loan as of December 31, 2011 and 2010 based on an index of the yield to maturity of CCC rated debt of other companies in the energy sector, resulting in Level 3 categorization.

(4)

In December 2010, the 2008 Loans were amended to, among other things: eliminate the "put rights" which had allowed the lenders to demand repayment of the 2008 Loans on the third, fifth, and seventh anniversaries thereof; allow for the early prepayment of the 2008 Loans; allow Cheniere for a limited period to sell Cheniere Partners common units held as collateral and prepay the 2008 Loans with the proceeds; and release restrictions on prepayments of other indebtedness at Cheniere as certain conditions are met. In addition, 96.6% of the lenders agreed to terminate their rights to exchange the 2008 Loans for Series B Preferred Stock of Cheniere. Pursuant to an amendment to the 2008 Loans adopted in September 2011, the outstanding principal amount of the 2008 Loans held by Scorpion is exchangeable for shares of Cheniere common stock at a price of $5.00 per share. The estimated fair value of the 2008 Loans as of December 31, 2011 and 2010 was determined to be the same as the carrying amount due to our ability to call the debt (other than the debt held by Scorpion) at anytime without penalty or a make-whole payment for an early redemption.

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(1)	We have made changes to the disclosed 2010 share-based compensation gross deferred tax asset and the disclosed 2010 investment in limited partnership gross deferred tax liability, which had a corresponding change in the 2010 valuation allowance. These changes do not affect the 2010 disclosed net deferred tax asset.

(2)	The federal net operating loss ("NOL") carryforward expires between 2017 and 2031. The state NOL carryforward expires between 2020 and 2026.

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(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 terminal segment are primarily from tug revenues from Cheniere Marketing and the receipt of 80% of gross margins earned by Cheniere Marketing in monetizing the TUA capacity of Cheniere Energy Investments, LLC ("Cheniere Investments") at the Sabine Pass LNG terminal in the year ended December 31, 2011. These LNG terminal segment intersegment revenues are eliminated with intersegment expenses in our Consolidated Statements of Operations.

(3)

Intersegment losses related to our LNG and natural gas marketing segment are primarily from Cheniere Marketing's tug costs and the payment of 80% of gross margins earned by Cheniere Marketing in monetizing the TUA capacity of Cheniere Investments at the Sabine Pass LNG terminal in the year ended December 31, 2011. These LNG terminal segment intersegment costs are eliminated with intersegment revenues in our Consolidated Statements of Operations.

(4)

Intersegment revenues related to our LNG terminal segment are primarily from TUA capacity reservation fee revenues and tug revenues of $125.5 million and $250.2 million that were received from our LNG and natural gas marketing segment for the years ended December 31, 2010 and 2009, respectively. These LNG terminal segment intersegment revenues are eliminated with intersegment expenses in our Consolidated Statements of Operations.

(5)

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

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(6)

Intersegment losses related to our LNG and natural gas marketing segment are primarily from TUA capacity reservation fee expenses and tug costs of $125.5 million and $250.2 million that were incurred from our LNG terminal segment for the years ended December 31, 2010 and 2009, respectively. These costs and 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 costs and expenses are eliminated with intersegment revenues in our Consolidated Statements of Operations.

(7)	Intersegment losses related to corporate and other are from various transactions between our LNG 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.

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(a)	Financial Statements, Schedules and Exhibits

(1)	Financial Statements—Cheniere Energy, Inc. and Subsidiaries:

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(2)	Financial Statement Schedules:

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(1)	Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2011, our cash payments for interest would be $18.6 million in 2012.

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(1)	Amounts represent equity losses of affiliates not funded by Cheniere.

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