CEI 2011 Form 10K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K



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

For the fiscal year ended December 31, 2011



o	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 of registrant 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)

Registrant’s telephone number, including area code: (713) 375-5000

Securities registered pursuant to Section 12(b) of the Act:



Common Stock, $ 0.003 par value	NYSE Amex Equities
(Title of Class)	(Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(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 o No x

The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $758,000,000 as of June 30, 2011.

129,607,257 shares of the registrant’s Common Stock were outstanding as of February 15, 2012.

Documents incorporated by reference: The definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) is incorporated by reference into Part III.

CHENIERE ENERGY, INC.

TABLE OF CONTENTS




PART I	1
Items 1. and 2. Business and Properties	1
General	1
Our Business Strategy	2
Market Factors	2
Corporate Structure	3
Business Segments	4
LNG Terminal Business	4
Natural Gas Pipeline Business	11
LNG and Natural Gas Marketing Business	13
Subsidiaries	15
Employees and Labor Relations	15
Available Information	15
Item 1A. Risk Factors	16
Risks Relating to Our Financial Matters	16
Risks Relating to Our LNG Terminal Business	19
Risks Relating to Our Natural Gas Pipeline Business	22
Risks Relating to Our LNG and Natural Gas Marketing Business	24
Risks Relating to Our LNG Business in General	24
Risks Relating to Our Business in General	27
Item 1B. Unresolved Staff Comments	29
Item 3. Legal Proceedings	29
Item 4. Mine Safety Disclosure	29
PART II	30
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 6. Selected Financial Data	31
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation	33
Introduction	33
Overview of Business	33
Overview of Significant Events	33
Liquidity and Capital Resources	34
Contractual Obligations	44
Results of Operations	44
Off-Balance Sheet Arrangements	48
Inflation and Changing Prices	48
Summary of Critical Accounting Policies and Estimates	48
Recent Accounting Standards	51
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	51
Item 8. Financial Statements and Supplementary Data	53
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	88
Item 9A. Controls and Procedures	88
Item 9B. Other Information	88
PART III	88
PART IV	88
Item 15. Exhibits and Financial Statement Schedules	88

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

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

•

statements 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;

•

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.

These forward-looking statements are often identified by the use of terms and phrases such as "achieve," "anticipate," "believe," "contemplate," "develop," "estimate," "expect," "forecast," "plan," "potential," "project," "propose," "strategy" and similar terms and phrases, or by the use of future tense. 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 are made as of the date of this annual report and speak only as of the date of this annual report.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in "Risk Factors." All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors.

DEFINITIONS

In this annual report, unless the context otherwise requires:


•	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.

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

Cheniere Energy, Inc. (NYSE Amex Equities: LNG), a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. We own and operate the Sabine Pass LNG terminal in Louisiana through our 88.8% ownership interest in and management agreements with Cheniere Energy Partners, L.P. ("Cheniere Partners") (NYSE Amex Equities: CQP), which is a publicly traded partnership that we created in 2007. We also own and operate the Creole Trail Pipeline, which interconnects the Sabine Pass LNG terminal with natural gas markets in North America. Approximately one-half of the receiving capacity at the Sabine Pass LNG terminal is contracted to two international oil companies. One of our subsidiaries, Cheniere Marketing, LLC ("Cheniere Marketing"), is marketing LNG and natural gas on its own behalf and on behalf of Cheniere Partners, monetizing the other half of the LNG receiving capacity at the Sabine Pass LNG terminal. Cheniere Partners is developing a project to add liquefaction capabilities at the Sabine Pass LNG terminal through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"). We are in various stages of developing other projects, including LNG and other marine hydrocarbon terminals and pipeline related projects, each of which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision. Unless the context requires otherwise, references to the "Company", "Cheniere", "we", "us" and "our" refer to Cheniere Energy, Inc. and its subsidiaries, including our publicly traded subsidiary partnership, Cheniere Partners.

LNG is natural gas that, through a refrigeration process, has been reduced to a liquid state that occupies approximately 1/600th of its gaseous volume. LNG remains in a liquid state at -160 degrees Celsius (-260 degrees Fahrenheit) at atmospheric pressure. Liquefying natural gas allows it to be economically transported from areas of the world where natural gas is abundant and inexpensive to produce to areas where natural gas production and other imports are insufficient to meet demand. LNG is transported from liquefaction terminals to regasification facilities using oceangoing LNG vessels specifically constructed for this purpose.

LNG facilities are conventionally designed to either receive LNG or to produce LNG. The Sabine Pass LNG terminal has a receiving configuration with docks to berth LNG vessels, customized unloading arms and transfer piping, cryogenic storage tanks to temporarily store LNG that is unloaded from a vessel, and equipment that pressurizes and heats the LNG to a normal working pressure and temperature in natural gas transmission lines for delivery to markets that consume natural gas. In terminals with a production configuration, the marine, transfer and storage facilities are still required, but specialized feed gas treatment facilities and refrigeration facilities are required to cool the feed gas to its cryogenic state. In constructing the proposed liquefaction facilities at the Sabine Pass LNG terminal, Cheniere Partners proposes to take advantage of the existing marine and storage facilities that were constructed for the LNG receiving terminal, thereby saving a substantial amount of capital cost compared to the cost of constructing a greenfield facility.

Our Business Strategy

Our primary business strategy is to identify markets in which the development of marine hydrocarbon terminals presents an opportunity to develop assets based on long-term, take-or-pay type contracts. Our initial development of the Sabine Pass LNG terminal, based on contracts with Chevron U.S.A. Inc. ("Chevron") and Total Gas and Power North America, Inc. ("Total"), has provided us with the opportunity to expand the terminal to add liquefaction capabilities. We plan to implement our strategy by:


•	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.

Market Factors

Because we have entered into contracts to sell LNG from all four of the currently-planned LNG trains at the Sabine Pass LNG terminal, we anticipate that market factors affecting the U.S. natural gas market and global LNG market will have little impact on the commercial success of Cheniere Partners' liquefaction project. Similarly, we have entered into a lump-sum turnkey contract with Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") to construct the first two LNG trains of Cheniere Partners' liquefaction project. Therefore, we believe that global materials prices and labor costs will have little impact on the cost of LNG trains 1 and 2. Financing the construction of LNG trains 1 and 2 will be primarily dependent upon our ability to access capital markets at reasonable rates and our receipt of regulatory approvals. In order to construct LNG trains 3 and 4 of Cheniere Partners' liquefaction project, we may be affected by higher engineering, procurement, and construction costs, and we will again require access to capital markets at reasonable rates in order to finance construction.

Our ability to sell any seasonal quantities of LNG available from LNG trains 1, 2, 3 and 4 at the Sabine Pass LNG terminal, develop additional trains at the Sabine Pass LNG terminal, or develop other new projects is subject to a broader array of market factors, including: changes in worldwide supply and demand for natural gas, LNG and substitute products; the relative prices for natural gas, oil and substitute products in North America and international markets; economic growth in developing countries; investment in energy infrastructure; the rate of fuel switching for power generation from coal, nuclear, or oil to natural gas; and access to capital markets.

We expect global demand for natural gas to grow significantly as more nations are seeking environmentally cleaner and more abundant and reliable fuel alternatives to oil and coal. Industry sources indicate that global natural gas demand is projected to rise by over 2% per year through 2030, and global LNG demand is projected to rise at twice that rate, from 210 mtpa in 2010 to 483 mtpa in 2030. This projected increase in LNG demand is driven by a number of factors, including: continuing demand growth in Asia, the Middle East, and South America due primarily to a build-out of natural gas fired electric power generation capacity; a reduction in nuclear power generation in established LNG importing regions such as Japan and Europe; and switching from coal- and oil-fired power generation to power generated from natural gas. In addition, with continued population growth in developing countries, industrial consumption of natural gas is expected to continue to increase due to applications such as fertilizer production, which increase is also expected to be driven by fuel switching dynamics as global fertilizer producers switch from naphtha feedstock to natural gas feedstock.

While global natural gas consumption is rising internationally, natural gas production in North America has undergone a technological transformation that has resulted in a substantial increase in annual production capacity, decrease in the cost of production, and expansion of technically recoverable reserves. Technologies related to both horizontal drilling and hydraulic fracturing, which had been under development since the 1980s, have now allowed the exploration and production industry to develop unconventional reservoirs composed predominantly of shales, but also containing tight sands and coal seam methane. Unconventional reservoirs are also known as continuous reservoirs; they extend over very large geographic sections of North America. The primary obstacle in the development of these resources is not about finding the formations, but about designing optimal well placement for their most efficient exploitation. This has been greatly facilitated by new drilling technologies that permit very deep and long horizontal wells with drill bores located at single drilling sites to minimize the cycle time between wells and the environmental impact of drilling operations.

These technological improvements have significantly increased natural gas reserves and production capacity in North America; however, growth in demand for natural gas has not increased at the same rate. Since reaching a peak at over $13.00/MMBtu during 2008, natural gas prices have been on a declining trend ever since, and are now below $3.00/MMBtu. We believe that this development, coupled with global demand fundamentals and the fact that global LNG and natural gas prices have generally been linked to oil prices and relatively non-responsive to changes in aggregate natural gas supply, is a fundamental reason for Sabine Pass Liquefaction's success in entering into contracts with respect to Cheniere Partners' liquefaction project.

Our ability to continue to develop new facilities in the United States will be driven by the continued success of the North American upstream natural gas sector in exploiting new unconventional reservoirs, continuing to drive down costs and exploiting higher valued condensates and natural gas liquids in conjunction with natural gas production. Any such facilities will compete with other international LNG export projects principally on a price basis. These projects generally require development capital not only to build the marine, storage and liquefaction facilities, but also to drill wells and build processing and pipeline transportation infrastructure. Because we rely on the natural gas market and transportation infrastructure already existing in the United States, we generally require less capital expenditures and, therefore, are able to sell LNG at a lower price. Furthermore, because feed natural gas is purchased from the United States market at a Henry Hub related price, we can offer LNG for sale on an alternative price index that is not related to crude oil prices, thereby allowing our customers to realize the benefits of lower cost production in the United States while diversifying their portfolio of supply cost indices.

While development of unconventional natural gas resources in other regions may ultimately reduce demand for LNG in some markets over time, LNG serves a variety of requirements and is substantially more flexible than pipeline-delivered natural gas. We believe that this flexibility has intrinsic value beyond the price of natural gas and will continue to motivate demand even if unconventional resources are developed in regions such as Eastern Europe, China or South America.

We continue to evaluate global energy market fundamentals to identify opportunities to serve customers as needs arise, either from an importation, exportation or transportation perspective. We believe that our primary business model of entering into long-term, take-or-pay type contracts for infrastructure assets will provide a base on which to build a platform that permits the continued development of assets to serve the needs of our customers.

Corporate Structure

As of December 31, 2011, we held approximately 88.8% of Cheniere Partners, including 100% of its general partner. Although results are consolidated for financial reporting, we and Cheniere Partners operate with independent capital structures. Cash flow available to us from Cheniere Partners is primarily in the form of management fees and cash distributions declared and paid to us on our common units and general partner interest. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for more discussion on how we receive cash flow from Cheniere Partners.

The following diagram depicts our abbreviated capital structure, including our ownership of Cheniere Partners and Sabine Pass LNG, L.P. ("Sabine Pass LNG") as of December 31, 2011. On January 6, 2012, we repaid the $298 million term loan in full, leaving $487 million of debt outstanding at Cheniere Energy, Inc.

Business Segments

Our business activities are conducted by three operating segments for which we provide information in our consolidated financial statements for the years ended December 31, 2011, 2010 and 2009. These three segments are our:


•	LNG terminal business;


•	natural gas pipeline business; and


•	LNG and natural gas marketing business.

For information about our segments’ revenues, profits and losses and total assets, see Note 21—"Business Segment Information" of our Notes to Consolidated Financial Statements.

LNG Terminal Business

We began developing our LNG terminal business in 1999 and were among the first companies to secure sites and commence development of new LNG terminals in North America. We focused our development efforts on three LNG terminal projects: Sabine Pass LNG in western Cameron Parish, Louisiana on the Sabine Pass Channel; Corpus Christi LNG near Corpus Christi, Texas; and Creole Trail LNG at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. We constructed the Sabine Pass LNG terminal and are developing a project to add liquefaction capabilities at the Sabine Pass LNG terminal which is owned through Cheniere Partners, in which we hold an approximate 88.8% interest. We currently own 100% interests in both the Corpus Christi and Creole Trail LNG terminal projects.

Sabine Pass LNG Terminal

We have constructed the Sabine Pass LNG terminal in western Cameron Parish, Louisiana, on the Sabine Pass Channel. We have long-term leases for five tracts of land consisting of 1,015 acres. We are currently operating LNG receiving facilities at the terminal with regasification capacity of approximately 4.0 Bcf/d (with peak capacity of approximately 4.3 Bcf/d) and aggregate LNG storage capacity of approximately 16.9 Bcf. In addition, we are developing LNG liquefaction facilities at the terminal, which are designed for up to four LNG trains, each with a nominal production capacity of approximately 4.5 mtpa.

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d (with peak capacity of approximately 4.3 Bcf/d) and aggregate LNG storage capacity of approximately 16.9 Bcf. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which Sabine Pass LNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Capacity reservation fee TUA payments are made by Sabine Pass LNG's third-party TUA customers as follows:


•	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.

The remaining approximately 2.0 Bcf/d of regasification capacity has been reserved by Cheniere Partners through a TUA between Cheniere Investments and Sabine Pass LNG. Cheniere Investments is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year through at least September 30, 2028; however, the revenue earned by Sabine Pass LNG from Cheniere Investments' capacity payments under the TUA is eliminated upon consolidation of our financial statements. Cheniere Partners has guaranteed Cheniere Investments' obligations under its TUA. See "—LNG and Natural Gas Marketing Business" below for a discussion of the Variable Capacity Rights Agreement ("VCRA") between Cheniere Investments and Cheniere Marketing entered into in order to monetize Cheniere Investments' 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal.

Liquefaction Facilities

In June 2010, Cheniere Partners formed Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction") to own, develop and operate liquefaction facilities at the Sabine Pass LNG terminal. As currently contemplated, the liquefaction facilities are designed for up to four LNG trains, each with a nominal production capacity of approximately 4.5 mtpa. We anticipate LNG exports could commence as early as 2015 with each LNG train commencing operations approximately six to nine months after the previous LNG train.

The Department of Energy ("DOE") has granted Sabine Pass Liquefaction an order authorizing the export of up to the equivalent of 16 mtpa (approximately 800 Bcf) per year of domestically produced LNG by vessel from the Sabine Pass LNG terminal to Free Trade Agreement ("FTA") countries for a 30-year term, beginning on the earlier of the date of first export or September 7, 2020, and another order authorizing the export of up to the equivalent of 803 Bcf per year (approximately 16 mtpa) of domestically produced LNG by vessel from the Sabine Pass LNG terminal to non-FTA countries for a 20-year term, beginning on the earlier of the date of first export or May 20, 2016.

Sabine Pass Liquefaction has submitted an application to the FERC requesting authorization to site, construct and operate liquefaction and export facilities at the Sabine Pass LNG terminal, which we anticipate receiving in the first quarter of 2012.

Customers

Sabine Pass Liquefaction has entered into four LNG sale and purchase agreements ("SPA"), under which customers have committed to purchase, in aggregate, 834.0 million MMBtu of LNG per year (approximately 16 mtpa). The volume of LNG committed to be purchased by these customers represents approximately 89% of the expected nameplate liquefaction capacity that will be available upon completion of Cheniere Partners' proposed liquefaction facilities. In addition, upon completion of all four LNG trains, approximately 100 million MMBtu of LNG per year (approximately 2.0 mtpa) may be produced seasonally to be sold by Sabine Pass Liquefaction on a merchant basis. We anticipate that Sabine Pass Liquefaction will utilize Cheniere Investments' TUA capacity to provide LNG to Sabine Pass Liquefaction's customers.

In aggregate, these customers have agreed to pay Sabine Pass Liquefaction approximately $2.3 billion annually, plus an amount per MMBtu of LNG equal to 115% of the final settlement price for the New York Mercantile Exchange natural gas futures contract for the month in which the relevant cargo is scheduled. Subject to the conditions described below, sales charges will be paid by our SPA customers as follows:

•

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;

•

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;

•

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

•

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.

During an event of force majeure declared by BG or Gas Natural Fenosa or Sabine Pass Liquefaction, BG or Gas Natural Fenosa, as applicable, will continue to be obligated to pay the relevant fixed sales charge, subject to reduction under certain circumstances, for a period of 24 months, after which time such customer may have a right to terminate its SPA.

Each SPA has a term of 20 years commencing upon the date of first commercial delivery for the applicable LNG train, and an extension option of up to ten years, or for Gas Natural Fenosa in certain circumstances, up to 12 years. Each SPA is subject to certain conditions precedent, including but not limited to, Sabine Pass Liquefaction receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision to construct the applicable LNG train. Sabine Pass Liquefaction will designate the date for the first commercial delivery of LNG for each customer within the 180-day period commencing a specified number of months after the date that the conditions precedent have been satisfied or waived.

A customer has the right to terminate its SPA if, among other events, (i) Sabine Pass Liquefaction declares an event of force majeure one or more times and the resulting interruptions total 24 or more months in any 36 month period, and such force majeure events result in a reduction of 50 percent or more in the annualized annual contract quantity of LNG available to such customer during such periods of force majeure, (ii) with respect to BG and Gas Natural Fenosa, such customer declares a force majeure event for specified circumstances and such force majeure event has continued for 24 months and has resulted in a reduction in the quantity of LNG that such customer is able to take of at least 50 percent of the annualized contract quantity, (iii) Sabine Pass Liquefaction fails to make available to such customer a specified number of cargoes during a 12-month period, (iv) an applicable LNG train has not commenced commercial operations at the Sabine Pass LNG terminal within 180 days after the date designated

for first commercial delivery, (v) with respect to BG and Gas Natural Fenosa, Sabine Pass Liquefaction's authorizations to export LNG from the United States to either FTA or non-FTA countries has been withdrawn, revoked or expired, and such withdrawal, revocation or expiration does not constitute a force majeure, and with respect to GAIL, Sabine Pass Liquefaction's authorization to export LNG from the United States to non-FTA countries has expired, or (vi) with respect to BG and Gas Natural Fenosa, the specified limit on Sabine Pass Liquefaction's liability under the applicable SPA has been reached or exceeded.

Sabine Pass Liquefaction has the right to terminate a customer's SPA if, among other events, (i) any applicable guaranty provided by such customer ceases to be in effect in excess of a specified number of days, (ii) such customer or its applicable guarantor, if any, fails to execute certain agreements with financial lenders in a timely manner, (iii) with respect to GAIL and KOGAS, such customer fails to take 50 percent or more of the cargoes scheduled in any 12-month period, (iv) with respect to GAIL and KOGAS, such customer declares an event of force majeure one or more times and the resulting interruptions total 24 or months in any 36 month period, and such force majeure events result in such customer being prevented from taking 50 percent or more of the annualized annual contract quantity during such periods of force majeure, (v) such customer fails to comply with applicable trade laws or (vi) such customer violates provisions of the SPA restricting parties to which LNG can be marketed and sold.

Either a customer or Sabine Pass Liquefaction would have the right to terminate such customer's SPA if, among other events, (i) a bankruptcy event (as defined in the SPA) occurred with respect to the other party, (ii) the other party failed to pay amounts due under the SPA in excess of a specified dollar amount, (iii) the other party's business practices caused it to violate certain applicable laws or (iv) the conditions to the commencement of the 20-year term specified in the SPA were not satisfied or waived by December 31, 2012 with respect to BG (for LNG train 1) and Gas Natural Fenosa, or June 30, 2013 with respect to GAIL and KOGAS, or a later date if so agreed by the customer and Sabine Pass Liquefaction. In addition, either BG or Sabine Pass Liquefaction has the right to cancel LNG trains 2, 3 and 4 if Sabine Pass Liquefaction has not made a positive final investment decision to proceed with construction of the applicable LNG trains by June 30, 2013.

Construction

We expect to commence construction of LNG trains 1 and 2 during the first half of 2012 and begin operations in late 2015, with each LNG train commencing operations approximately six to nine months after the previous LNG train. We expect to complete our construction plan and cost estimates for LNG trains 3 and 4 by the end of 2012, begin construction by the end of the first quarter of 2013, and begin operations in 2017.

The cost to construct LNG trains 1 and 2 is currently estimated to be approximately $4.5 billion to $5.0 billion, before financing costs. Our cost estimates are subject to change due to such items as change orders, delays in construction, increased component and material costs, escalation of labor costs and increased spending to maintain our construction schedule.

In November 2011, Sabine Pass Liquefaction entered into a lump-sum turnkey agreement ("EPC Contract") with Bechtel, a major international engineering, procurement and construction contractor, for the procurement, engineering, design, installation, training, commissioning and placing into service of LNG trains 1 and 2 of the proposed liquefaction project. The EPC Contract provides that Sabine Pass Liquefaction will pay Bechtel a contract price of $3.9 billion, which is only subject to adjustment by change orders. Bechtel has the right, among other things, to submit change orders in the event Bechtel is adversely affected as a result of a delay in the commencement of construction beyond March 31, 2012. The EPC Contract also entitles Bechtel to a change order amending its rights and obligations to the extent it is adversely affected by any of the following: (i) a change in law, (ii) certain acts or omissions of Sabine Pass Liquefaction, (iii) force majeure, (iv) acceleration of work by Sabine Pass Liquefaction, (v) delay in delivery of insurance proceeds in the case of insured loss, (vi) suspension in work ordered by Sabine Pass Liquefaction, (vii) subsurface soil conditions materially different from those described in the geotechnical studies, (viii) discovery of hazardous materials for which Sabine Pass Liquefaction is responsible, (ix) physical damage caused by a third party not under Bechtel’s control and (x) other specified reasons in the EPC Contract. The EPC Contract entitles Sabine Pass Liquefaction to a change order unilaterally up to certain thresholds and thereafter upon request provided that agreement is reached on any changes to the contract price, project schedule, design, payment schedule, minimum acceptance criteria, performance guarantee and any other obligation of Bechtel under the EPC Contract.

In the EPC Contract, Bechtel warrants that the (i) equipment will be new (unless otherwise specified in the EPC Contract) and of good quality, (ii) work and the equipment will meet the requirements of the EPC Contract, including good engineering and construction practices and applicable laws, codes and standards and (iii) work and the equipment will be free from encumbrances to title. Until 18 months after substantial completion of each LNG train, Bechtel will be liable to promptly correct any work that is found defective with respect to such LNG train.

If an LNG train fails to achieve 95% of the performance guarantee set forth in the EPC Contract by the applicable guaranteed substantial completion date, then substantial completion of such LNG train will not occur and Bechtel will pay delay liquidated damages. In addition, Bechtel is required to attempt for 10 months thereafter to correct the work to enable the LNG train to achieve the minimum acceptance criteria and otherwise achieve substantial completion. If the LNG train has not achieved the minimum acceptance criteria and substantial completion at the end of this 10-month period, then Sabine Pass Liquefaction will have the option of either granting Bechtel an additional 10-month correction period or declaring a default. If an LNG train has not achieved the performance guarantee within a specified period after the guaranteed substantial completion date, then Bechtel is required to pay the applicable performance liquidated damages, and if substantial completion of an LNG train occurs after the applicable guaranteed substantial completion date, Bechtel will pay Sabine Pass Liquefaction the delayed liquidated damages as defined in the EPC Contract until substantial completion of such LNG train occurs. Bechtel will be entitled to receive specified bonuses for timely substantial completion of the LNG trains.

The EPC Contract has several termination rights:

•

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;

•

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;

•

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.

Bechtel’s liability under the EPC Contract is limited as specified in the EPC Contract, except that this limit does not apply to certain indemnification obligations, to Bechtel’s title warranty, or to Bechtel’s obligation to complete all work required to ensure that each LNG train is ready to receive natural gas and produce LNG.

The cost to construct LNG trains 3 and 4 is currently estimated to be approximately $4.5 billion to $5.0 billion, before financing costs. Sabine Pass Liquefaction has engaged Bechtel to complete front-end engineering and design work and to negotiate a lump-sum turnkey contract based on an open book estimate. Commencement of construction for LNG trains 3 and 4 is targeted during early 2013. Our cost estimates are subject to change due to such items as change orders, delays in construction, increased component and material costs, escalation of labor costs and increased spending to maintain our construction schedule.

Corpus Christi LNG Terminal

We formed Corpus Christi LNG, L.P. ("Corpus Christi LNG") in May 2003 to develop the Corpus Christi LNG terminal near Corpus Christi, Texas, which was designed and permitted by the FERC as a regasification terminal, although this order will expire in April 2012. The Corpus Christi site consists of approximately 1,030 acres and is located approximately sixty miles southeast of the Eagle Ford Shale.

In September 2011, we formed Corpus Christi Liquefaction, LLC ("Corpus Christi Liquefaction") to develop an LNG terminal at our Corpus Christi Liquefaction terminal site. As currently contemplated, the proposed Corpus Christi LNG Liquefaction LNG terminal would be designed for up to three LNG trains capable of producing in aggregate of up to 13.5 mtpa. In December 2011, Corpus Christi Liquefaction received approval from the FERC to begin the pre-filing process required to seek authorization to commence construction of the liquefaction project. Corpus Christi Liquefaction has engaged Bechtel to complete preliminary front-end engineering and design work.

Corpus Christi Liquefaction will contemplate making a final investment decision to commence construction of the Corpus Christi LNG Liquefaction LNG project upon, among other things, entering into acceptable commercial arrangements, obtaining an order to export domestically produced natural gas, receiving regulatory authorization to construct and operate the liquefaction assets and obtaining adequate financing.

Other LNG Terminal Sites

We continue to evaluate, and may develop, additional sites that we believe may be commercially desirable locations for LNG terminals and other facilities.

LNG Terminal Competition

All of the available capacity and services at the Sabine Pass LNG terminal has been fully contracted. Other LNG terminal sites that we may develop will compete for customers with other companies that are constructing and operating LNG receiving terminals and liquefaction facilities around the world. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to markets than we do.

LNG Terminal Governmental Regulation

Our LNG terminal operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. This regulatory burden increases the cost of constructing and operating the LNG terminals, and failure to comply with such laws could result in substantial penalties. Through construction, commissioning and operations of our existing facilities, we have been in substantial compliance with all regulations discussed herein.

FERC

In order to site and construct our proposed LNG terminals, we must receive and are required to maintain authorization from the FERC under Section 3 of the Natural Gas Act of 1938, as amended ("NGA"). We will be required to obtain and maintain authorizations from the FERC to site, construct and operate liquefaction and export facilities at the Sabine Pass LNG and Corpus Christi LNG terminal sites. In addition, orders from the FERC authorizing construction of an LNG terminal are typically subject to specified conditions that must be satisfied throughout the construction, commissioning and operation of LNG terminals. Throughout the life of our LNG terminals, they will be subject to regular reporting requirements to the FERC and the U.S. Department of Transportation regarding the operation and maintenance of the facilities.

In 2005, the Energy Policy Act of 2005 ("EPAct") was signed into law. The EPAct gave the FERC exclusive authority to approve or deny an application for the siting, construction, expansion or operation of an LNG terminal. The EPAct amended the NGA to prohibit market manipulation. The EPAct increased civil and criminal penalties for any violations of the NGA, Natural Gas Policy Act of 1978, as amended, and any rules, regulations or orders of the FERC, up to $1.0 million per day per violation. In accordance with the EPAct, the FERC issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud.

Other Federal Governmental Permits, Approvals and Consultations

In addition to the FERC authorization under Section 3 of the NGA, our construction and operation of LNG terminals and related projects, and the construction of our proposed liquefaction facilities, are also subject to additional federal permits, orders, approvals and consultations required by other federal agencies, including: DOE, Advisory Council on Historic Preservation, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, U.S. Environmental Protection Agency ("EPA") and U.S. Department of Homeland Security.

Our LNG terminals are also subject to U.S. Department of Transportation safety regulations and standards for the transportation and storage of LNG and regulations of the U.S. Coast Guard relating to maritime safety and facility security. Moreover, our LNG terminals are also subject to state and local laws, rules and regulations.

LNG Terminal Environmental Regulation

Our LNG terminal operations, including the proposed liquefaction facilities, are subject to various federal, state and local laws and regulations relating to the protection of the environment. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial liabilities for non-compliance or releases. Failure to comply with these laws and regulations may also result in substantial civil and criminal fines and penalties.

Clean Air Act ("CAA")

Our LNG terminal operations, including the proposed liquefaction facilities, are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing other air emission-related issues. We do not believe, however, that our operations, or the construction and operations of our proposed liquefaction facilities, will be materially and adversely affected by any such requirements.

The U.S. Supreme Court has ruled that the EPA has authority under existing legislation to regulate carbon dioxide and other heat-trapping gases in mobile source emissions. Mandatory reporting requirements were promulgated by the EPA and finalized in 2009. This rule requires mandatory reporting for greenhouse gases from stationary fuel combustion sources. An additional section, which requires reporting for all fugitive emissions throughout LNG terminals, was finalized in December 2010. In addition, Congress has considered proposed legislation directed at reducing "greenhouse gas emissions." It is not possible at this time to predict how future regulations or legislation may address greenhouse gas emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, financial position, results of operations and cash flows.

Coastal Zone Management Act ("CZMA")

Our LNG terminals, including the proposed liquefaction facilities, are subject to the requirements of the CZMA throughout the construction of facilities located within the coastal zone. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources, and in Texas, by the Railroad Commission and the General Land Office). This program is implemented in coordination with the Department of the Army construction permitting process to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act ("CWA")

Our LNG terminal operations are subject to the federal CWA and analogous state and local laws. Pursuant to certain requirements of the CWA, the EPA has adopted regulations concerning discharges of wastewater and storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit.

Resource Conservation and Recovery Act ("RCRA")

The federal RCRA and comparable state statutes govern the disposal of "hazardous wastes." In the event any hazardous wastes are generated in connection with our LNG terminal operations, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

Endangered Species Act

Our LNG terminal operations and planned activities, including our proposed liquefaction facilities, may be restricted by requirements under the Endangered Species Act, which seeks to ensure that human activities neither jeopardize endangered or threatened animal, fish and plant species nor destroy or modify their critical habitats.

National Historic Preservation Act ("NHPA")

Construction of our proposed liquefaction facilities will be subject to requirements under Section 106 of the NHPA. The NHPA requires projects to take into account the effects of their actions on historic properties. These programs are administered by the State Historic Preservation Officers ("SHPOs"). Any areas where ground disturbance will occur are required to be reviewed by the affected SHPOs.

Natural Gas Pipeline Business

We formed Cheniere Pipeline Company, a wholly owned subsidiary, to develop natural gas pipelines to provide access to North American natural gas markets for customers of our LNG terminals. We are also developing other pipeline projects not primarily related to our LNG terminals. Our pipeline systems developed in conjunction with our LNG terminals will interconnect with multiple interstate pipelines, providing a means of transporting natural gas between trading points in the Gulf Coast and our LNG terminals. Our other projects are market-focused, seeking to connect natural gas supplies to growing markets. Our ultimate decisions regarding further development of new pipeline projects will depend upon future events, including, in particular, customer preferences and general market demand for pipeline transportation of natural gas from or to a particular LNG terminal.

Creole Trail Pipeline

The Creole Trail Pipeline is a permitted 153-mile natural gas pipeline. We have constructed, placed in-service and are operating the first 94 miles of the Creole Trail Pipeline, connecting the Sabine Pass LNG terminal to numerous interconnection points with existing interstate and intrastate natural gas pipelines in southwest Louisiana. The remaining 59 miles of permitted natural gas pipeline, if constructed, will traverse east starting at the terminus of the first 94 miles of natural gas pipeline, with interconnections to additional existing interstate natural gas pipelines.

Cheniere Marketing and other third parties have entered into interruptible transportation agreements with Creole Trail Pipeline to transport natural gas from the Sabine Pass LNG terminal into North American natural gas markets.

In connection with Cheniere Partners' proposed liquefaction facilities at the Sabine Pass LNG terminal, we are developing a project for the Creole Trail Pipeline to be able 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. We will contemplate making a final investment decision to commence construction of the expansion project upon, among other things, entering into acceptable commercial and financing arrangements.

We will contemplate making a final investment decision to construct the remaining 59 miles of permitted natural gas pipeline upon, among other things, entering into acceptable commercial and financing arrangements.

Other Pipelines

We continue to evaluate, and may develop, additional pipelines that we believe may be commercially desirable based on customer preferences and general market demand for natural gas.

We will contemplate making a final investment decision to commence construction of our proposed natural gas pipelines upon, among other things, entering into acceptable commercial and financing arrangements and applying for and receiving governmental authorization to construct and operate the natural gas pipelines.

Natural Gas Pipeline Competition

Our existing and proposed pipelines will compete with intrastate and interstate pipelines throughout the U.S. Gulf Coast region. The principal elements of competition among pipelines are rates, terms of service, access to supply and flexibility and reliability of service. In addition, the FERC’s continuing efforts to increase competition in the natural gas industry are increasing the natural gas transportation options of a pipeline’s traditional customers.

Our pipelines will face competition from other interstate and/or intrastate pipelines that connect with our LNG terminals. In particular, our Creole Trail Pipeline competes with the Kinder Morgan Louisiana Pipeline owned by Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”). Kinder Morgan has built a 3.2 Bcf/d take-away pipeline system from the Sabine Pass LNG terminal. Total and Chevron have both signed agreements with Kinder Morgan securing 100% of the initial capacity on the Kinder Morgan Louisiana Pipeline for 20 years.

Natural Gas Pipeline Governmental Regulation

Interstate Natural Gas Pipelines

Under the NGA, the FERC is granted authority to approve, and if necessary, set "just and reasonable rates" for the transportation or sale of natural gas in interstate commerce. In addition, under the NGA, we are not permitted to unduly discriminate or grant undue preference as to our rates or the terms and conditions of service. The FERC has the authority to grant certificates allowing construction and operation of facilities used in interstate gas transportation and authorizing the provision of services. Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate consumption for domestic, commercial, industrial, or any other use, and to natural gas companies engaged in such transportation or sale. However, the FERC’s jurisdiction does not extend to the production, gathering, or local distribution of natural gas.

In general, the FERC’s authority to regulate interstate natural gas pipelines and the services that they provide includes:


•	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.

Failure to comply with the NGA can result in the imposition of administrative, civil and criminal remedies, including civil and criminal penalties of up to $1.0 million per day per violation under the EPAct.

For a number of years the FERC has implemented certain rules referred to as Standards of Conduct aimed at ensuring that an interstate natural gas pipeline not provide certain affiliated entities with preferential access to transportation service or non-public information about such service. These rules have been subject to revision by the FERC from time to time, most recently in 2008 when the FERC issued a final rule, Order No. 717, on Standards of Conduct for Transmission Providers. Order No. 717

eliminated the concept of energy affiliates and adopted a "functional approach" that applies Standards of Conduct to individual officers and employees based on their job functions, not on the company or division in which the individual works. The general principles of the Standards of Conduct are: non-discrimination, independent functioning, no conduit and transparency. These general principles govern the relationship between marketing function employees conducting transactions with affiliated pipeline companies and transportation function employees. We have established the required policies and procedures to comply with the Standards of Conduct and are subject to audit by the FERC to review compliance, policies and our training programs.

Our pipelines that interconnect with our LNG terminals are interstate natural gas pipelines. We are required to obtain authorization from the FERC pursuant to Section 7 of the NGA to construct and operate these pipelines. The rates that we charge are subject to the FERC's regulation under Sections 4 and 5 of the NGA. Our interstate pipelines also are subject to the FERC's open access requirements and the FERC's Standards of Conduct. The FERC's exercise of jurisdiction over interstate natural gas pipelines is substantially broader than its exercise of jurisdiction over LNG terminals.

Natural Gas Pipeline Safety Act

Louisiana and Texas administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended ("NGPSA"), which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal remedies.

The Pipeline Safety Improvement Act of 2002, as amended ("PSIA"), which is administered by the U.S. Department of Transportation Office of Pipeline Safety, governs the areas of testing, education, training and communication. The PSIA requires pipeline companies to perform extensive integrity tests on natural gas transportation pipelines that exist in high population density areas designated as "high consequence areas." Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs for gas transportation pipelines, which requires pipeline operators to 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 preventive and mitigation actions.

In 2010, the U.S. Department of Transportation issued a final rule (known as "Control Room Management Rule") requiring pipeline operators to write and institute certain control room procedures that address human factors and fatigue management. Existing Creole Trail Pipeline written control room management procedures are being implemented per the schedule in the final rule.

Energy Policy Act of 2005

The EPAct and the FERC’s policies promulgated thereunder contain numerous provisions relevant to the natural gas industry and to interstate pipelines. See "—LNG Terminal Business—LNG Terminal Governmental Regulation" above.

Natural Gas Pipeline Environmental Regulation

Our natural gas pipeline business is subject to the same federal, state and local laws and regulations relating to the protection of the environment that are applicable to our LNG terminals. See "—LNG Terminal Business—LNG Terminal Environmental Regulation" above.

LNG and Natural Gas Marketing Business

Our wholly owned subsidiary, Cheniere Marketing, is engaged in the LNG and natural gas marketing business and is seeking to develop a portfolio of long-term, short-term, and spot LNG purchase and sale agreements, assist Cheniere Investments in negotiating with potential customers to monetize its 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal, and enter into business relationships for the domestic marketing of natural gas imported by Cheniere Marketing as LNG to the Sabine Pass LNG terminal.

Cheniere Marketing has been purchasing, transporting and unloading commercial LNG cargoes into the Sabine Pass LNG terminal and has used trading strategies intended to maximize margins on these cargoes. In addition, Cheniere Marketing has continued to enter into various business relationships to facilitate purchasing and selling commercial LNG cargoes.

In 2010, Cheniere Marketing entered into various agreements ("LNGCo Agreements") with JPMorgan LNG Co. ("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 arranging for transporting, receiving, storing, hedging and regasifying LNG cargoes. Cheniere Marketing does not have the authority to contractually bind LNGCo under the LNGCo Agreements. In the event LNGCo declines to purchase an LNG cargo presented to it by Cheniere Marketing under the LNGCo Agreements, Cheniere Marketing may pursue the opportunity on its own behalf or present it to third parties. The term of the LNGCo Agreements expires in April 2012; however, either party may terminate the agreements without penalty prior to such date. 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 depending upon the gross margins of each transaction and the aggregate gross margin earned during the term of the LNGCo Agreements.

In connection with monetizing Cheniere Investments’ reserved capacity under its TUA at the Sabine Pass LNG terminal, Cheniere Marketing has entered into the VCRA. Pursuant to the VCRA, Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. To the extent payments from Cheniere Marketing to Cheniere Investments under the VCRA or new Cheniere Partners' business increase Cheniere Partners' available cash in excess of the common unit and general partner distributions and certain reserves, the cash would be distributed to Cheniere in the form of distributions on Cheniere’s subordinated units and related general partner distributions. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs under the Cheniere Investments TUA. Cheniere has guaranteed all of Cheniere Marketing's payment obligations under the VCRA.

LNG and Natural Gas Marketing Competition

In purchasing LNG, we compete for supplies of LNG with:


•	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.

In marketing LNG and natural gas, we compete for sales of LNG and natural gas with a variety of competitors, including:


•	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.

LNG and Natural Gas Marketing Governmental Regulation

In 1992 and 1993, the FERC concluded that sellers of short-term or long-term natural gas supplies would not have market power over the sale for resale of natural gas. The FERC established light-handed regulation over sales for resale of natural gas and adopted regulations granting blanket certificates to allow entities selling natural gas to make interstate sales for resale at negotiated rates. In 2003, the FERC amended the blanket marketing certificates to require that all sellers adhere to a code of conduct with respect to natural gas sales. The code of conduct addresses such matters as natural gas withholding, manipulation of market prices, communication of accurate information and record retention.

The EPAct contains provisions intended to prohibit the manipulation of the natural gas markets and is applicable to our LNG, pipeline and natural gas marketing businesses. See "—LNG Terminal Business—LNG Terminal Governmental Regulation" and "—Natural Gas Pipeline Business—Natural Gas Pipeline Governmental Regulation."

The prices at which we sell natural gas are not regulated, insofar as the interstate market is concerned and, for the most part, are not subject to state regulation. We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate automatically granted by the FERC. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, under "—Natural Gas Pipeline Business—Natural Gas Pipeline Governmental Regulation," the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.

Subsidiaries

Our assets are generally held by or under our operating subsidiaries. We conduct most of our operations through these subsidiaries, including our operations relating to the development and operation of our LNG terminal business, the development and operation of our pipeline business and the development and operation of our LNG and natural gas marketing business.

Employees and Labor Relations

We had 232 full-time employees at February 15, 2012, including 124 employees who directly supported the Sabine Pass LNG terminal operations. We consider our current employee relations to be favorable.

Available Information

Our principal executive offices are located at 700 Milam Street, Suite 800, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is http://www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission ("SEC") under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

We will also make available to any stockholder, without charge, copies of our Annual Report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Cheniere Energy, Inc., Investor Relations Department, 700 Milam Street, Suite 800, Houston, Texas 77002 or call (713) 562-5000. In addition, the public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers, like us, that file electronically with the SEC.

ITEM 1A. RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operations, financial condition, liquidity and prospects.

The risk factors in this report are grouped into the following categories:


•	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.

Risks Relating to Our Financial Matters

Our existing level of cash resources, negative operating cash flow and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, financial condition and prospects.

As of December 31, 2011, we had $459.2 million of cash and cash equivalents and $185.1 million of restricted cash and cash equivalents, and we had $3.0 billion of total debt outstanding on a consolidated basis (before debt discounts), although we repaid $298.0 million of this debt in January 2012. We incur significant interest expense relating to the assets at the Sabine Pass LNG terminal, and we anticipate needing to incur additional debt and issue equity to finance the construction of Cheniere Partners' proposed liquefaction project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access capital markets. In addition, if we do not make a final investment decision to construct LNG trains 1 and 2 by December 31, 2012, we may not be able to refinance our existing indebtedness when it matures, including the Convertible Senior Unsecured Notes and the Senior Notes. Our costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs.

We have not been profitable historically, and we have not had positive operating cash flow. Our ability to achieve profitability and generate positive operating cash flow in the future is subject to significant uncertainty.

We had net losses of $198.8 million, $76.2 million and $161.5 million for the years ended December 31, 2011, 2010 and 2009, respectively. In addition, our net cash flow used in operating activities was $42.8 million, $16.9 million and $97.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. In the future, we may incur operating losses and experience negative operating cash flow. We may not be able to reduce costs, increase revenues, or reduce our debt service obligations sufficiently to maintain our cash resources, which could cause us to have inadequate liquidity to continue our business.

In order to generate needed amounts of cash, we may sell equity or equity-related securities or assets, including equity interests in Cheniere Partners. Such sales could dilute our stockholders' proportionate indirect interests in the assets, business operations and proposed liquefaction and other projects of Cheniere Partners or other subsidiaries, and could adversely affect the market price of our common stock.

We have pursued and are pursuing a number of alternatives in order to generate needed amounts of cash, including potential issuances and sales of additional equity or equity-related securities by us, Cheniere Partners, or both, and potential sales of assets, including units of limited partner interest that we currently hold in Cheniere Partners. Such sales, in one or more transactions, could dilute our stockholders' proportionate indirect interests in the assets, business operations and proposed projects of Cheniere Partners, including its proposed liquefaction project, or in other subsidiaries. In addition, such sales, or the anticipation of such sales, could adversely affect the market price of our common stock.

Our ability to generate needed amounts of cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason.

Our future results and liquidity are substantially dependent upon performance by Chevron and Total, each of which has entered into a TUA with Sabine Pass LNG and agreed to pay us approximately $125 million annually, and, upon satisfaction of the conditions precedent to payment thereunder, by BG, Gas Natural Fenosa, GAIL, and KOGAS, each of which has entered into an SPA with Sabine Pass Liquefaction and agreed to pay us approximately $723 million, $454 million, $548 million and $548 million annually, respectively. We are dependent on each customer's continued willingness and ability to perform its obligations under its contract. We are also exposed to the credit risk of any guarantor of these customers' obligations under their respective contracts in the event that we must seek recourse under a guaranty. If any customer fails to perform its obligations under its contract, our business, results of operations, financial condition and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the contract.

Each customer's contract at the Sabine Pass LNG terminal is subject to termination under certain circumstances.

Each of Sabine Pass LNG's long-term TUAs and Sabine Pass Liquefaction's SPAs contains various termination rights. For example, each of Sabine Pass LNG's customers may terminate its TUA if the Sabine Pass LNG terminal experiences a force majeure delay for longer than 18 months, fails to redeliver a specified amount of natural gas in accordance with the customer's redelivery nominations or fails to accept and unload a specified number of the customer's proposed LNG cargoes. Each of Sabine Pass Liquefaction's customers may terminate its SPA under the circumstances described under "Items 1. and 2. Business and Properties—LNG Terminal Business—Sabine Pass LNG Terminal—Liquefaction Facilities—Customers." We may not be able to replace these TUAs or SPAs on desirable terms, or at all, if they are terminated.

Sabine Pass LNG may be restricted under the terms of the Sabine Pass Indenture from making distributions under certain circumstances, which may limit Cheniere Partners' ability to pay or increase distributions to us, which could materially and adversely affect us.

The Sabine Pass Indenture restricts payments that Sabine Pass LNG can make to Cheniere Partners in certain events and limits the indebtedness that Sabine Pass LNG can incur. Sabine Pass LNG is permitted to pay distributions to Cheniere Partners only after the following payments have been made:


•	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.

In addition, Sabine Pass LNG will only be able to make distributions to Cheniere Partners in the event that it could, among other things, incur at least $1.00 of additional indebtedness under the fixed charge coverage ratio test of 2:1 at the time of payment and after giving pro forma effect to the distribution. Sabine Pass LNG is also prohibited under the Sabine Pass Indenture from paying distributions to Cheniere Partners or incurring additional indebtedness upon the occurrence of any of the following events, among others:


•	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;


•	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.

Sabine Pass LNG's inability to pay distributions to Cheniere Partners or to incur additional indebtedness as a result of the foregoing restrictions in the Sabine Pass Indenture may inhibit Cheniere Partners' ability to pay or increase distributions to us and its other unitholders.

The fixed charge coverage ratio test contained in the Sabine Pass Indenture could prevent Sabine Pass LNG from making cash distributions. As a result, Cheniere Partners may be prevented from making distributions to us, which could materially and adversely affect us.

Sabine Pass LNG is not permitted to make cash distributions if its consolidated cash flow is not at least twice its fixed charges, calculated as required in the Sabine Pass Indenture. In order to satisfy this fixed charge coverage ratio test, we estimate that Sabine Pass LNG's consolidated cash flow, as defined in the Sabine Pass Indenture, must be greater than approximately $375 million. Thus, TUA payments from Cheniere Investments are needed in addition to the TUA payments from Chevron and Total.

The fixed charge coverage ratio test contained in the Sabine Pass Indenture may not be met if Cheniere Investments' payments to Sabine Pass LNG cease to be recognizable as revenue under U.S. generally accepted accounting principles ("GAAP"), which could occur for future periods if, for example, GAAP guidelines for recognition of revenue from affiliates change or LNG trains 1 and 2 do not timely commence operations and Cheniere Investments changes its business such that it is not pursuing, and has no prospect of developing, any substantive business, thereby causing it to lack economic substance. If the fixed charge coverage ratio test is not satisfied, Sabine Pass LNG will not be permitted by the Sabine Indenture to make distributions to Cheniere Partners, which may prevent Cheniere Partners from making distributions to us and its other unitholders, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

The Sabine Pass Indenture may prevent Sabine Pass LNG from engaging in certain beneficial transactions.

In addition to restrictions on the ability of Sabine Pass LNG to make distributions or incur additional indebtedness, the Sabine Pass Indenture also contains various other covenants that may prevent it from engaging in beneficial transactions, including limitations on the ability of Sabine Pass LNG or certain of its subsidiaries to:


•	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.

Risks Relating to Our LNG Terminal Business

Operation of the Sabine Pass LNG terminal, and other facilities that we may construct, involves significant risks.

As more fully discussed in these Risk Factors, the Sabine Pass LNG terminal and our other existing and proposed facilities face operational risks, including the following:


•	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.

To maintain the cryogenic readiness of the Sabine Pass LNG terminal, Sabine Pass LNG may need to purchase and process LNG. Sabine Pass LNG's TUA customers have the obligation to procure LNG if necessary for the Sabine Pass LNG terminal to maintain its cryogenic state. If they fail to do so, Sabine Pass LNG may need to procure such LNG.

Sabine Pass LNG needs to maintain the cryogenic readiness of the Sabine Pass LNG terminal. Together with Cheniere Investments, the two third-party TUA customers have the obligation to maintain minimum inventory levels, and under certain circumstances, to procure LNG to maintain the cryogenic readiness of the terminal. In the event that aggregate minimum inventory levels are not maintained, Sabine Pass LNG has the right to procure a cryogenic readiness cargo, and to the extent that the TUA customers have failed to maintain their minimum inventory levels, be reimbursed by each TUA customer for their allocable share of the LNG acquisition costs. If Sabine Pass LNG is not able to obtain financing on acceptable terms, it will need to maintain sufficient working capital for such a purchase until it receives reimbursement for the allocable costs of the LNG from its TUA customers or sells the regasified LNG. Sabine Pass LNG may also bear the commodity price and other risks of purchasing LNG, holding it in its inventory for a period of time and selling the regasified LNG.

Sabine Pass LNG may be required to purchase natural gas to provide fuel at the Sabine Pass LNG terminal, which would increase operating costs and could have a material adverse effect on our results of operations.

Sabine Pass LNG's TUAs provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG terminal, which it uses primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. There is a risk that this 2% in-kind deduction will be insufficient for these needs and that Sabine Pass LNG will have to purchase additional natural gas from third parties. Sabine Pass LNG will bear the cost and risk of changing prices for any such fuel.

Hurricanes or other disasters could adversely affect us.

In August and September of 2005, Hurricanes Katrina and Rita damaged coastal and inland areas located in Texas, Louisiana, Mississippi and Alabama. Construction at the Sabine Pass LNG terminal site was temporarily suspended in connection with Hurricane Katrina, as a precautionary measure. Approximately three weeks after the occurrence of Hurricane Katrina, the Sabine Pass LNG terminal site was again secured and evacuated in anticipation of Hurricane Rita, the eye of which made landfall to the east of the site. As a result of these 2005 storms and related matters, the Sabine Pass LNG terminal experienced construction delays and increased costs. In September 2008, Hurricane Ike struck the Texas and Louisiana coast, and the Sabine Pass LNG terminal experienced damage.

Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal or related infrastructure, as well as delays or cost increases in the construction of Cheniere Partners' proposed liquefaction facilities or our other facilities. If there are changes in the global climate, storm frequency and intensity may increase; should it result in rising seas, our coastal operations would be impacted.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development, construction and operation of our facilities could impede operations and construction and could have a material adverse effect on us.

The design, construction and operation of LNG terminals and other facilities, and the import and export of LNG, are highly regulated activities. The FERC's approval under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to construct and operate an LNG facility. Although Sabine Pass LNG has obtained all of the necessary authorizations to operate the Sabine Pass LNG receiving terminal, Sabine Pass Liquefaction will need authorization from the FERC to construct and operate Cheniere Partners' proposed liquefaction facilities. Such authorizations are subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

The construction of Cheniere Partners' project to add liquefaction capacity at the Sabine Pass LNG terminal will be subject to a number of development risks, which could cause cost increases and delays or prevent completion of the project.

Key factors that may affect the timing of, and our ability to complete, the project at the Sabine Pass LNG terminal to add liquefaction capacity include, but are not limited to:


•	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.

Delays in the construction of the proposed liquefaction facilities at the Sabine Pass LNG terminal beyond the estimated development periods, as well as change orders to the EPC contract with Bechtel, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until the proposed liquefaction facilities are constructed (which could cause further delays). Any delay in completion of the proposed liquefaction facilities may also cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Cheniere Partners may not be successful in implementing its proposed business strategy to provide liquefaction capabilities at the Sabine Pass LNG terminal.

A significant element of our strategy to monetize our reserved capacity at the Sabine Pass LNG terminal is to develop liquefaction facilities at the terminal, construction of which has not yet commenced. Cheniere Partners' proposed liquefaction facilities will require very significant financial resources, which may not be available on terms reasonably acceptable to us or at all. Our contract with Bechtel to construct the first two LNG trains requires that we secure financing in the amount of the contract price by March 31, 2012 or Bechtel has the right to submit change orders, which may result in higher costs. Our SPAs with BG, Gas Natural Fenosa, GAIL and KOGAS also contain certain conditions precedent, including, but not limited to, receiving regulatory

approvals, securing necessary financing arrangements and making a final investment decision to construct the liquefaction facilities. If these conditions are not met by December 31, 2012 with respect to BG (for LNG train 1) and Gas Natural Fenosa and June 30, 2013 with respect to GAIL and KOGAS, either party may terminate the contract. In addition, if Sabine Pass Liquefaction has not made a positive final investment decision regarding the Train 2 Tranche, the Train 3 Tranche or the Train 4 Tranche by June 30, 2013, then BG may cancel such tranche(s) that are not yet decided affirmatively. If we are unable to obtain adequate and timely financing on satisfactory terms, Bechtel, BG, Gas Natural Fenosa, GAIL and KOGAS may terminate their respective contracts with us, and we may not be able to enter into contracts with another contractor or customer on similar terms or at all.

It will take several years to construct the liquefaction facilities, and we do not expect the first LNG train to be operational until at least 2015. Even if successfully constructed, the liquefaction facilities would be subject to many of the same operating risks described herein with respect to the Sabine Pass LNG terminal. Accordingly, there are many risks associated with Cheniere Partners' proposed liquefaction facilities, and if we are not successful in implementing our business strategy, we may not be able to generate additional cash flows, which could have a material adverse impact on our business, results of operations, financial condition, liquidity and prospects.

The cost of constructing Cheniere Partners' proposed liquefaction facilities will be dependent on several items, including change orders. As a result, if completed, the actual construction cost of these facilities may be significantly higher than our current estimates, which are before financing costs and contingencies.

As construction progresses, we may decide or be forced to submit change orders to Bechtel that could result in a longer construction period and higher construction costs. Our contract with Bechtel to construct the first two LNG trains requires that we secure financing in the amount of the contract price by March 31, 2012 or Bechtel has the right to submit change orders, which may result in higher costs. As a result, any significant change orders or increases in commodity prices could increase our anticipated costs and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

We are dependent on Bechtel and other contractors for the successful completion of Cheniere Partners' proposed liquefaction facilities.

Timely and cost-effective completion of Cheniere Partners' proposed LNG liquefaction facilities in compliance with agreed specifications is central to our business strategy and is highly dependent on contractors' performance under their agreements. Our contractors' ability to perform successfully under their contracts is dependent on a number of factors, including their ability to:


•	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.

Although some contracts may provide for liquidated damages, if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable LNG liquefaction facility, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the project or result in a contractor's unwillingness to perform further work on the project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

We may not be able to purchase natural gas on economical terms or at all to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

Under the SPAs with our liquefaction customers, we are required to deliver to them a specified amount of LNG at specified times. However, we may not be able to purchase sufficient quantities of natural gas to satisfy those delivery obligations, which may provide affected SPA customers with the right to terminate their SPAs. Even if we are able to purchase sufficient quantities of natural gas, our cost to do so may be greater than the price that our SPA customers have agreed to pay for LNG under their SPAs. Our failure to purchase sufficient quantities of natural gas or to purchase natural gas at prices below what our SPA customers have agreed to pay for LNG could have a material adverse effect on our business, results of operations, financial condition and prospects.

Sabine Pass LNG terminal operations are and will be subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses that could have a material adverse effect on us.

The operation of the Sabine Pass LNG terminal's regasification facilities is, and the proposed liquefaction facilities will be, subject to the inherent risks associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of the Sabine Pass LNG terminal site and assets or damage to persons and property. In addition, operations at the Sabine Pass LNG terminal site and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Risks Relating to Our Natural Gas Pipeline Business

Our existing and proposed pipelines will be dependent upon a few potential customers, and our pipeline business could be materially and adversely affected if we lost any one of those customers.

We do not currently have any third-party, firm transportation customers for our existing or proposed pipelines. We anticipate increased usage of the Creole Trail Pipeline to transport natural gas to the proposed liquefaction facilities at the Sabine Pass LNG terminal once construction of the liquefaction facilities is completed and the Creole Trail Pipeline has been modified. Failure to construct the Sabine Pass LNG liquefaction facilities, failure to make the capital improvements necessary to provide transportation to the Sabine Pass LNG liquefaction facilities, or failure to obtain any third-party, firm transportation customers could have a material adverse impact on our natural gas pipeline business.

Our natural gas pipelines, including their FERC gas tariffs, are subject to FERC regulation.

Our FERC tariffs contain pro forma transportation agreements, which must be filed and approved by the FERC. Before we enter into a transportation agreement with a shipper that contains a term that materially deviates from our tariff, we must seek FERC approval. The FERC may approve the material deviation in the transportation agreement; however, in that case, the materially deviating terms must be made available to our other similarly-situated customers. If we fail to seek FERC approval of a transportation agreement that materially deviates from our tariff, or if the FERC audits our contracts and finds deviations that appear to be unduly discriminatory, the FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation.

The FERC could change its current ratemaking policies, and those changes could have adverse effects on our pipelines.

Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.

The Federal Office of Pipeline Safety requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:


•	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.

We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with the Office of Pipeline Safety's rules and related regulations and orders, we could be subject to penalties and fines.

Any reduction in the capacity of, or the allocations to, interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines, which would adversely affect our revenues and cash flow.

We will be dependent upon third-party pipelines and other facilities to provide delivery options to and from our pipelines. If any pipeline connection were to become unavailable for volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any permanent interruption at any key pipeline interconnect which caused a material reduction in volumes transported on our pipelines could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development and operation of our natural gas pipelines would have a detrimental effect on us and our pipeline projects.

The design, construction and operation of natural gas pipelines and the transportation of natural gas are all highly regulated activities. FERC approval under Section 7 of the NGA, as well as several other material state governmental and regulatory approvals and permits, are required in order to construct and operate a pipeline. We must also obtain several other material governmental and regulatory approvals and permits in order to construct and operate pipelines, including several under the CAA and the CWA from the U.S. Army Corps of Engineers and state environmental agencies. We have no control over the timing of the review and approval process nor can we predict the outcome of the process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any third parties will attempt to interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in the projects. Failure to obtain and maintain any of these approvals and permits could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Our pipeline business could be materially and adversely affected if we lose the right to situate our pipelines on property owned by third parties.

We do not own the land on which our pipelines are situated, and we are subject to the possibility of increased costs to retain necessary land use rights. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.

Risks Relating to Our LNG and Natural Gas Marketing Business

Our use of hedging arrangements may adversely affect our future results of operations or liquidity.

To reduce our exposure to fluctuations in the price, volume and timing risk associated with the marketing of LNG and natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange ("ICE") and NYMEX, or over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when:


•	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.

Our hedging arrangements may also limit the benefit that we would receive from increases in the prices for natural gas. The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

The limited capital resources and credit available to our LNG and natural gas marketing business may limit our ability to develop that business.

We have limited capital available to our LNG and natural gas marketing business. The business also currently has limited access to third-party sources of financing. Other investment-grade marketing companies have greater financial resources than we do. Our LNG and natural gas marketing business continues to develop and implement its business strategy and may not generate sufficient revenues and cash flows to cover the significant fixed costs of the business.

Our exposure to the performance and credit risks of counterparties under agreements may adversely affect our results of operations, liquidity and access to financing.

Our LNG and natural gas marketing business involves our entering into various purchase and sale, hedging and other transactions with numerous third parties (commonly referred to as "counterparties"). In such arrangements, we are exposed to the performance and credit risks of our counterparties, including the risk that one or more counterparties fails to perform its obligation to make deliveries of commodities and/or to make payments. These risks may increase during periods of commodity price volatility. Defaults by suppliers and other counterparties may adversely affect our results of operations, liquidity and access to financing.

Risks Relating to Our LNG Businesses in General

We may not construct or operate any additional LNG facilities beyond those currently planned, which could limit our growth prospects.

We may not construct some of our proposed LNG facilities, including the proposed Corpus Christi LNG terminal or natural gas pipelines, whether due to lack of commercial interest or inability to obtain financing or otherwise. Our ability to develop additional regasification or liquefaction facilities will also depend on the availability and pricing of LNG and natural gas in North America and other places around the world. Competitors may have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to sources of natural gas and LNG than we do. If we are unable or unwilling to construct and operate additional LNG facilities, our prospects for growth will be limited.

Decreases in the demand for and price of natural gas could lead to reduced development of LNG projects worldwide, which could adversely affect the regasification component of our LNG businesses and the performance of our TUA customers and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

The development of domestic LNG facilities and LNG projects generally is based on assumptions about the future price of natural gas and the availability of natural gas. Natural gas prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:


•	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.

Adverse trends or developments affecting any of these factors could result in decreases in the price of natural gas, leading to reduced development of LNG projects worldwide. Such reductions could adversely affect the regasification component of our LNG businesses and the performance of our TUA customers and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Cyclical or other changes in the demand for LNG capacity may adversely affect our LNG businesses and the performance of our customers and could reduce our operating revenues and may cause us operating losses.

The economics of our LNG businesses could be subject to cyclical swings, reflecting alternating periods of under-supply and over-supply of LNG import or export capacity and available natural gas, principally due to the combined impact of several factors, including:


•	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.

These factors could materially and adversely affect our ability, and the ability of our current and prospective customers, to procure supplies of LNG to be imported into North America and to procure customers for LNG or regasified LNG at economical prices, or at all.

Various economic and political factors could negatively affect the continued development of LNG facilities, including Cheniere Partners' proposed liquefaction facilities which could adversely affect our LNG businesses and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Commercial development of an LNG facility takes a number of years, requires a substantial capital investment and may be delayed by factors such as:


•	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.

There may be shortages of LNG vessels worldwide, which could adversely affect our LNG businesses and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

The construction and delivery of LNG vessels require significant capital and long construction lead times, and the availability of the vessels could be delayed to the detriment of our LNG businesses and our customers because of:


•	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.

Terrorist attacks or military campaigns may adversely impact our LNG businesses.

A terrorist or military incident involving an LNG facility or LNG carrier may result in delays in, or cancellation of, construction of new LNG facilities, including our LNG terminals and related natural gas pipelines and proposed liquefaction facilities, which would increase our costs and decrease our cash flows. A terrorist incident may also result in temporary or permanent closure of existing LNG facilities, including ours, which could increase our costs and decrease our cash flows, depending on the duration of the closure. Operations at our LNG facilities could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our LNG businesses and our customers, including their ability to satisfy their obligations to us under the commercial agreements.

Risks Relating to Our Business in General

We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

The construction and operation of our LNG terminals, including Cheniere Partners' proposed liquefaction facilities, and pipelines are and will be subject to the inherent risks associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

Existing and future environmental and similar laws and regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.

Our business is and will be subject to extensive federal, state and local laws and regulations that control, among other things, discharges to air and water; the handling, storage and disposal of hazardous chemicals, hazardous waste, and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our LNG terminals, including liquefaction facilities, and pipelines and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. Violation of these laws and regulations could lead to substantial fines and penalties or to capital expenditures related to pollution control equipment that could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of an LNG terminal, including a liquefaction facility, or pipeline, we could be liable for the costs of cleaning up hazardous substances released into the environment and for damage to natural resources.

There are numerous regulatory approaches currently in effect or being considered to address greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, and regulation by the EPA. For example, the adoption of frequently proposed legislation implementing a carbon tax on energy sources that emit carbon dioxide into the atmosphere may have a material adverse effect on the ability of our customers (i) to import LNG, if imposed on them as importers of potential emission sources, or (ii) to sell regasified LNG, if imposed on them or their customers as natural gas suppliers or consumers. In addition, as we consume retainage gas at the Sabine Pass LNG terminal, this carbon tax may also be imposed on us directly.

Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from the Sabine Pass LNG terminal through the Sabine Pass Channel, could cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain key personnel could adversely affect us.

We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our LNG terminals, liquefaction facilities and pipelines and to provide our customers with the highest quality service. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. For example, in the aftermaths of Hurricanes Katrina and Rita, Bechtel and certain subcontractors temporarily experienced a shortage of available skilled labor necessary to meet the requirements of the Sabine Pass LNG terminal construction plan. As a result, we agreed to change orders with Bechtel concerning additional activities and expenditures to mitigate the hurricanes' effects on the construction of the Sabine Pass LNG terminal. Any increase in our operating costs could materially and adversely affect our business, results of operations, financial condition, liquidity and prospects.

We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could seriously harm us.

Our lack of diversification could have an adverse effect on our financial condition and results of operations.

Substantially all of our anticipated revenue in 2012 will be dependent upon one facility, the Sabine Pass LNG receiving terminal and related pipeline located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass LNG terminal or pipeline, or in the LNG industry, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

We may engage in operations or make substantial commitments and investments located, or enter into agreements with counterparties located, outside the United States, which would expose us to political, governmental and economic instability and foreign currency exchange rate fluctuations.

Conducting operations or making commitments and investments located, or entering into agreements with counterparties located, outside of the United States will cause us to be affected by economic, political and governmental conditions in the countries where we engage in business. Any disruption caused by these factors could harm our business. Risks associated with operations, commitments and investments outside of the United States include the risks of:


•	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.

Because our reporting currency is the United States dollar, any of our operations conducted outside the United States or denominated in foreign currencies would face additional risks of fluctuating currency values and exchange rates, hard currency shortages and controls on currency exchange. We would be subject to the impact of foreign currency fluctuations and exchange rate changes on our reporting for results from those operations in our consolidated financial statements.

We may incur impairments to goodwill or long-lived assets.

We review our long-lived assets, including goodwill and other intangible assets, for impairment annually in the fourth quarter or whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. 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 to our 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. 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 December 31, 2011, there were no threatened or pending legal matters that would have a material impact on our consolidated results of operations, financial position or cash flows.

ITEM 4. MINE SAFETY DISCLOSURE

None.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER

PURCHASES OF EQUITY SECURITIES

Our common stock has traded on the NYSE Amex Equities under the symbol LNG since March 24, 2003. The table below presents the high and low daily closing sales prices of the common stock, as reported by the NYSE Amex Equities, for each quarter during 2010 and 2011.



	High		Low
Three Months Ended
March 31, 2010	$	3.55	$	2.49
June 30, 2010	5.20		2.55
September 30, 2010	3.04		2.36
December 31, 2010	6.20		2.63
Three Months Ended
March 31, 2011	$	10.38	$	6.25
June 30, 2011	11.76		7.49
September 30, 2011	10.64		5.07
December 31, 2011	11.93		4.00

As of February 15, 2012, we had 129.6 million shares of common stock outstanding held by approximately 241 record owners.

We have never paid a cash dividend on our common stock. We currently intend to retain earnings to finance the growth and development of our business and do not anticipate paying any cash dividends on the common stock in the foreseeable future. Any future change in our dividend policy will be made at the discretion of our board of directors in light of our financial condition, capital requirements, earnings, prospects and any restrictions under any financing agreements, as well as other factors the board of directors deems relevant.

Issuer Purchases of Equity Securities

During the twelve months ended December 31, 2011, we purchased 1.9 million shares of restricted stock at an average cash price of $8.42 per share related to restricted stock that vested during 2011 and that was returned to the Company by employees to cover taxes.

Total Stockholder Return

The following graph compares the cumulative total stockholder return on our common stock against the S&P Oil and Gas Exploration and Production Index, and the Russell 2000 Index for the five years ended December 31, 2011. The graph was constructed on the assumption that $100 was invested in our common stock, the S&P Oil & Gas Exploration & Production Index and the Russell 2000 Index on December 31, 2006 and that any dividends were fully reinvested.



Company / Index	2007	2008	2009	2010	2011
Cheniere Energy, Inc.	113	10	8	19	30
Russell 2000 Index	98	65	83	105	101
S&P Oil & Gas Exploration & Production	144	95	134	147	137

ITEM 6. SELECTED FINANCIAL DATA

Selected financial data set forth below are derived from our audited consolidated financial statements for the periods indicated. The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report.



	Year Ended December 31,
	(in thousands, except per share data)
	2011			2010			2009			2008			2007
Revenues	$	290,444		$	291,513		$	181,126		$	7,144		$	647
LNG terminal and pipeline development expense	40,803			11,971			223			10,556			34,656
LNG terminal and pipeline operating expense	39,101			42,415			36,857			14,522			—
Depreciation, depletion and amortization	63,405			63,251			54,229			24,346			6,393
General and administrative expense (1)	88,427			68,626			65,830			122,678			122,046
Restructuring charges (2)	—			—			20			78,704			—
Income (loss) from operations	58,146			104,623			23,496			(244,188		)	(163,940		)
Gain (loss) from equity method investment (3)	—			128,330			—			(4,800		)	(191		)
Gain (loss) on early extinguishment of debt (4)	—			(50,320		)	45,363			(10,691		)	—
Derivative gain (loss)	(2,251		)	461			5,277			4,652			—
Interest expense, net	(259,393		)	(262,046		)	(243,295		)	(147,136		)	(119,360		)
Interest income	348			534			1,405			20,337			82,635
Non-controlling interest	4,582			2,191			6,165			8,777			3,425
Net loss	(198,756		)	(76,203		)	(161,490		)	(372,959		)	(196,580		)
Net loss per share attributable to common stockholders - basic and diluted	$	(2.60	)	$	(1.37	)	$	(3.13	)	$	(7.87	)	$	(3.89	)
Weighted average number of common shares outstanding - basic and diluted	76,483			55,765			51,598			47,365			50,537



	December 31,
	2011			2010			2009			2008			2007
Cash and cash equivalents	$	459,160		$	74,161		$	88,372		$	102,192		$	296,530
Restricted cash and cash equivalents (current)	102,165			73,062			138,309			301,550			228,085
Working capital	6,492			99,276			220,063			350,459			427,511
Non-current restricted cash and cash equivalents	82,892			82,892			82,892			138,483			478,225
Non-current restricted U.S. Treasury securities	—			—			—			20,829			63,923
Property, plant and equipment, net	2,107,129			2,157,597			2,216,855			2,170,158			1,645,112
Debt issuances costs, net	33,356			41,656			47,043			55,688			41,449
Goodwill	76,819			76,819			76,819			76,844			76,844
Total assets	2,915,325			2,553,507			2,732,622			2,920,082			2,959,743
Current debt, net of discount	492,724			—			—			—			—
Long-term debt, net of discount	2,465,113			2,918,579			2,692,740			2,750,308			2,657,579
Long-term debt-related parties, net of discount	9,598			8,930			349,135			332,054			—
Long-term deferred revenues	25,500			29,994			33,500			37,500			40,000
Total liabilities	3,088,317			3,026,117			3,164,749			3,194,136			2,879,317
Total stockholders’ deficit	$	(172,992	)	$	(472,610	)	$	(649,732	)	$	(524,216	)	$	(205,249	)


(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.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATION

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 "Financial Statements and Supplementary Data." 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 include the following subjects:


•	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

Overview of Business

We own and operate the Sabine Pass LNG terminal in Louisiana through our 88.8% ownership interest in and management agreements with Cheniere Energy Partners, L.P. ("Cheniere Partners") (NYSE Amex Equities: CQP), which is a publicly traded partnership that we created in 2007. We also own and operate the Creole Trail Pipeline, which interconnects the Sabine Pass LNG terminal with natural gas markets in North America. One of our subsidiaries, Cheniere Marketing, LLC ("Cheniere Marketing"), is marketing LNG and natural gas on its own behalf and on behalf of Cheniere Partners, and is working to monetize LNG storage and regasification capacity reserved by Cheniere Partners at the Sabine Pass LNG terminal. Cheniere Partners is developing a project to add liquefaction capabilities at the Sabine Pass LNG terminal. We are in various stages of developing other projects, including LNG terminal and pipeline related projects, each of which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision.

Overview of Significant Events

Our significant accomplishments since January 1, 2011 include the following:


•	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.

•

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.

•

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).

•

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).

Liquidity and Capital Resources

Although consolidated for financial reporting, Cheniere, Sabine Pass LNG and Cheniere Partners operate with independent capital structures. We expect the cash needs for Sabine Pass LNG's operating activities for at least the next twelve months will be met through operating cash flows and existing unrestricted cash. We expect the cash needs for Cheniere Partners' operating activities for at least the next twelve months will be met through operating cash flows from Sabine Pass LNG and existing unrestricted cash. We expect the cash needs of Cheniere's operating activities for at least the next twelve months will be met by utilizing existing unrestricted cash, management fees from Sabine Pass LNG and Cheniere Partners, distributions from our investment in Cheniere Partners and operating cash flows from our pipeline and LNG and natural gas marketing businesses.

The following table presents (in thousands) Cheniere's restricted and unrestricted cash and cash equivalents for each portion of our capital structure as of December 31, 2011. All restricted and unrestricted cash and cash equivalents held by Cheniere Partners and Sabine Pass LNG are considered restricted as to usage or withdrawal by Cheniere:



	Sabine Pass LNG			Cheniere Partners			Other Cheniere		Consolidated Cheniere
Cash and cash equivalents	$	—		$	—		$	459,160	$	459,160
Restricted cash and cash equivalents	100,394		(1)	77,147		(2)	7,516		185,057
Total	$	100,394		$	77,147		$	466,676	$	644,217


(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.

As of December 31, 2011, we had unrestricted cash and cash equivalents of $459.2 million available to Cheniere. In addition, we had consolidated restricted cash and cash equivalents of $185.1 million (which included cash and cash equivalents and other working capital available to Cheniere Partners, in which we own an 88.8% interest, and Sabine Pass LNG) designated for the following purposes: $96.1 million for interest payments related to the Senior Notes described below; $4.3 million for Sabine Pass LNG's working capital; $77.1 million for Cheniere Partners' working capital; and $7.5 million for other restricted purposes.

During the second quarter of 2011, we reclassified $298.0 million of debt from a long-term liability to a current liability because our 2007 Term Loan described below was due within 12 months as of May 31, 2011. During the third quarter of 2011, we reclassified $190.7 million, net of discount, of debt from a long-term liability to a current liability because our Convertible Senior Unsecured Notes were due within 12 months as of August 15, 2011. In December 2011, we closed an underwritten public offering of 41,745,000 shares of our common stock, which were sold to the public at a price per share of $8.35, resulting in net proceeds of approximately $330.9 million. In January 2012, we used a portion of the net proceeds to repay in full the outstanding principal balance of the $298.0 million 2007 Term Loan due May 31, 2012. The aggregate repayment amount was $298.2 million, including the outstanding principal amount and accrued interest through January 5, 2012.

In September 2011, we initiated an at-the-market program to sell up to 10 million shares of our common stock. As of December 31, 2011, we had sold 1.5 million shares with net proceeds of $14.4 million. During the year ended December 31, 2011, we paid $0.4 million in commissions to Miller Tabak + Co., Inc., as sales agent, in connection with the at-the-market program.

We believe that we will have sufficient unrestricted cash, liquid assets, cash generated from our operations and proceeds from capital market transactions to satisfy our debt obligations and fund our operations for at least the next 12 months. In order to satisfy our principal payment due on our Convertible Senior Unsecured Notes in August 2012, we will need to extend, refinance or repay such indebtedness, which may be accomplished by refinancing our existing indebtedness, raising capital by issuing equity, debt or other securities or using cash generated from selling assets or through a combination of the foregoing and will be dependent on factors such as worldwide natural gas and capital market conditions.

LNG Terminal Business

Cheniere Partners

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. We own approximately 88.8% of Cheniere Partners in the form of 12.0 million common units, 135.4 million subordinated units and a 2% general partner interest. Cheniere Partners owns a 100% interest in Sabine Pass LNG, which is operating the Sabine Pass LNG terminal, and a 100% interest in Sabine Pass Liquefaction, which is developing a liquefaction project at the Sabine Pass LNG terminal.

We receive quarterly equity distributions from Cheniere Partners, and we receive management fees for managing Sabine Pass LNG and Cheniere Partners. For the year ended December 31, 2011, we received $19.0 million in distributions on our common units, no distributions on our subordinated units and $1.0 million in distributions on our general partner interest. During the year ended December 31, 2011, we received fees of $10.8 million and $8.1 million under our management agreements with Cheniere Partners and Sabine Pass LNG, respectively.

Cheniere Partners' common unit and general partner distributions are being funded from cash flows generated by Sabine Pass LNG's two third-party TUA customers. The subordinated unit distributions that we received in 2010 were funded from cash flows generated by Sabine Pass LNG's TUA with Cheniere Marketing. Effective July 1, 2010, Cheniere Marketing assigned its TUA with Sabine Pass LNG for 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal to Cheniere Energy Investments, LLC ("Cheniere Investments"), a wholly owned subsidiary of Cheniere Partners. As a result of Cheniere Marketing's assignment of its TUA to Cheniere Investments, we have not received distributions on our subordinated units since the distribution made with respect to the quarter ended March 31, 2010.

During the subordination period, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the initial quarterly distribution of $0.425 per quarter, plus any arrearages in the payment of the initial quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units that we own. As a result of Cheniere Marketing's assignment of its TUA to Cheniere Investments, Cheniere Marketing no longer makes the approximately $250 million per year of payments to Sabine Pass LNG, and Cheniere Partners will not make distributions on our subordinated units unless it generates additional cash flow from Sabine Pass LNG's excess capacity or new business. Therefore, distributions to us on our subordinated units and conversion of the subordinated units into common units will depend upon the future business development of Cheniere Partners. We expect that additional cash flows generated by Cheniere Partners' proposed liquefaction project or other new Cheniere Partners' business would be used to make quarterly distributions on our subordinated units before any increase in distributions to the common unitholders.

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 Bcf/d of regasification capacity under the Cheniere Investments TUA (as discussed below) and develop new projects through either internal development or acquisition to increase cash flow. The fixed management fees payable by Sabine Pass LNG remain unchanged.

Concurrently with the TUA assignment, Cheniere Investments entered into a Variable Capacity Rights Agreement ("VCRA") with Cheniere Marketing. Under the terms of the VCRA, Cheniere Marketing is responsible for monetizing Cheniere Investments' TUA capacity at the Sabine Pass LNG terminal and is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG it arranges for delivery to the Sabine Pass LNG terminal. To the extent payments from Cheniere Marketing to Cheniere Investments under the VCRA or new Cheniere Partners' business 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 and related general partner distributions. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs under Cheniere Investments' TUA. Cheniere has guaranteed all of Cheniere Marketing's payment obligations under the VCRA.

In January 2011, Cheniere Partners initiated an at-the-market program to sell up to 1.0 million common units, the proceeds from which are used primarily to fund development costs associated with its proposed liquefaction project at the Sabine Pass LNG terminal. As of December 31, 2011, Cheniere Partners had sold 0.5 million common units with net proceeds of $9.0 million.

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 at a price of $15.25 per common unit. Cheniere Partners received net proceeds of approximately $60 million from this offering that it is using for general business purposes, including development costs associated with its proposed liquefaction project at the Sabine Pass LNG terminal.

Sabine Pass LNG Terminal

Approximately 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which Sabine Pass LNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Capacity reservation fee TUA payments are made by Sabine Pass LNG's third-party TUA customers as follows:


•	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.

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.

Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered for the customer's account.

Cheniere Partners is also developing proposed liquefaction facilities at the Sabine Pass LNG terminal. As currently contemplated, the liquefaction facilities are designed for up to four LNG trains, each with a nominal production capacity of approximately 4.5 mtpa. We expect to commence construction of LNG trains 1 and 2 during the first half of 2012 and begin operations in 2015, with each LNG train commencing operations approximately six to nine months after the previous LNG train. We estimate that the aggregate total cost to complete construction of the proposed liquefaction facilities will be approximately $9.0 billion to $10.0 billion, before financing costs. Our cost estimates are subject to change due to such items as change orders, increased component and material costs, escalation of labor costs and increased spending to maintain our construction schedule.

In November 2011, Sabine Pass Liquefaction entered into a lump-sum turnkey EPC agreement with Bechtel for construction of LNG trains 1 and 2 of the liquefaction project for $3.9 billion. The contract price is only subject to adjustment by change order, including by Bechtel if it is adversely affected as a result of a delay in the commencement of construction beyond March 31, 2012.

As of December 31, 2011, Cheniere Partners had paid $45.9 million of development costs relating to the proposed liquefaction facilities using its cash from operations and equity proceeds from the issuance of 4.1 million common units in September 2011. We expect to finance the construction costs of the proposed liquefaction project from a combination of project financing and debt and equity offerings.

Other LNG terminals

We will contemplate making final investment decisions to construct our proposed Corpus Christi LNG terminal and any other LNG terminal project upon, among other things, entering into acceptable commercial and financing arrangements for the applicable project.

Natural Gas Pipeline Business

The Creole Trail Pipeline, consisting of 94 miles of natural gas pipeline, is currently in-service and operating. Cheniere Marketing and other third parties have entered into interruptible transportation agreements with Creole Trail Pipeline to transport natural gas from the Sabine Pass LNG terminal into North American natural gas markets. Although Cheniere Marketing and other third parties have entered into interruptible transportation agreements with Creole Trail Pipeline to transport natural gas from the Sabine Pass LNG terminal into North American natural gas markets, there are no significant cash flows generated from the Creole Trail Pipeline.

In connection with Cheniere Partners’ proposed liquefaction facilities at the Sabine Pass LNG terminal, we are developing a project to add additional capabilities to the Creole Trail Pipeline to be able to provide transportation services to the liquefaction facilities.

We will contemplate making a final investment decision to construct the remaining 59 miles 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 the Burgos Hub project), 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.

LNG and Natural Gas Marketing Business

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 our 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 an 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 LNG is sold. Generally, 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 LNG is actually sold.

LNGCo Agreements

In 2010, Cheniere Marketing entered into various agreements ("LNGCo Agreements") with JPMorgan LNG Co. ("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 arranging for transporting, receiving, storing, hedging and regasifying LNG cargoes. Cheniere Marketing does not have the authority to contractually bind LNGCo under the LNGCo Agreements. In the event LNGCo declines to purchase an LNG cargo presented to it by Cheniere Marketing under the LNGCo Agreements, Cheniere Marketing may pursue the opportunity on its own behalf or present it to third parties. The term of the LNGCo Agreements expires in April 2012; however, either party may terminate the agreements without penalty prior to such date. 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 depending upon the gross margins of each transaction and the aggregate gross margin earned during the term of the LNGCo Agreements.

During the years ended December 31, 2011 and 2010, we recognized $12.0 million and $10.1 million, respectively, of marketing and trading revenues from LNGCo. As of December 31, 2011, the carrying amount of Cheniere Marketing’s assets relating to LNGCo, which is equivalent to Cheniere Marketing's maximum exposure to loss, was $3.0 million. A portion of this $3.0 million represents our fixed fee receivable and is reported as accounts and interest receivable on our consolidated financial statements, and the remaining portion represents our margin deposit receivable and is reported as prepaid expense and other current assets on our consolidated financial statements and is to be paid to Cheniere Marketing upon the completion or termination of the LNGCo Agreements.

Corporate and Other Activities

We are required to maintain corporate general and administrative functions to serve our business activities described above.

Sources and Uses of Cash

The following table summarizes (in thousands) the sources and uses of our cash and cash equivalents for the years ended December 31, 2011, 2010 and 2009. 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.



	Year Ended December 31,
	2011			2010			2009
Sources of cash and cash equivalents
Sale of common stock, net	$	468,598		$	—		$	—
Sale of common units by Cheniere Partners	52,351			—			—
Use of restricted cash and cash equivalents	—			34,423			241,101
Distribution from limited partner investment in Freeport LNG	—			3,900			15,300
Proceeds from sale of limited partner investment in Freeport LNG	—			104,330			—
Other	—			104			—
Total sources of cash and cash equivalents	520,949			142,757			256,401

Uses of cash and cash equivalents
Operating cash flow	(42,764		)	(16,920		)	(97,857		)
Repurchases and prepayments of debt	—			(104,681		)	(30,030		)
Distributions to non-controlling interest	(28,215		)	(26,393		)	(26,392		)
Investment in Cheniere Partners	(17,806		)	—			—
LNG terminal and pipeline construction-in-process, net	(8,934		)	(4,223		)	(112,317		)
Purchase of treasury shares	(14,363		)	(2,844		)	(999		)
Investment in restricted cash and cash equivalents	(15,914		)	—			—
Other	(7,954		)	(1,907		)	(2,626		)
Total uses of cash and cash equivalents	(135,950		)	(156,968		)	(270,221		)

Net increase (decrease) in cash and cash equivalents	384,999			(14,211		)	(13,820		)
Cash and cash equivalents—beginning of year	74,161			88,372			102,192
Cash and cash equivalents—end of year	$	459,160		$	74,161		$	88,372

Sale of Common Stock, net

In June 2011, we sold 12.7 million shares of Cheniere common stock in an underwritten public offering at a price of $10.35 per share. In December 2011, we sold 41.7 million shares of common stock in an underwritten public offering at a price of $8.35 per share. The Company intends to use the net proceeds from the offerings for general corporate purposes, including repayment of indebtedness.

Sale of Common Units by Cheniere Partners

In January 2011, Cheniere Partners initiated an at-the-market program to sell up to 1.0 million common units, the proceeds from which have primarily been used to fund development costs associated with Cheniere Partners' proposed liquefaction project at the Sabine Pass LNG terminal. As of December 31, 2011, Cheniere Partners had received $9.0 million in net proceeds from its sale of common units related to this at-the-market program.

In September 2011, Cheniere Partners sold 3.0 million common units in an underwritten public offering and 1.1 million common units to our subsidiary, Cheniere Common Units Holding, LLC, at a price of $15.25 per common unit. Cheniere Partners is using the net proceeds from the offering for general business purposes, including development costs for the proposed liquefaction facilities at the Sabine Pass LNG terminal.

Use of Restricted Cash and Cash Equivalents

In 2010, the $34.4 million of restricted cash and cash equivalents was used primarily to make distributions of $26.4 million to non-controlling interest holders, pay for construction activities at the Sabine Pass LNG terminal of $4.2 million and incur costs for other individually immaterial items of $3.8 million.

In 2009, the $241.1 million of restricted cash and cash equivalents was used primarily to pay for construction activities at the Sabine Pass LNG terminal of $112.3 million, and to make distributions of $26.4 million to non-controlling interest holders. In addition, in June 2009, through an amendment of the 2008 Loans described below, we moved $65.2 million out of the TUA reserve account into an unrestricted cash and cash equivalents account.

The decreased use of restricted cash and cash equivalents during 2010 primarily resulted from substantially completing construction of the Sabine Pass LNG terminal during the third quarter of 2009, and the decreased use in 2009 primarily resulted from completing construction of the initial sendout capacity of approximately 2.6 Bcf/d and storage capacity of approximately 10.1 Bcf at the Sabine Pass LNG terminal in September 2008.

Distribution from Limited Partner Investment in Freeport LNG

In 2010 and 2009, we received $3.9 million and $15.3 million of distributions from Freeport LNG, respectively. In May 2010, we sold our investment in Freeport LNG and, therefore, have not received distributions since that date.

Proceeds from Sale of Limited Partner Investment in Freeport LNG

We sold our 30% limited partner interest in Freeport LNG to institutional investors for net proceeds of $104.3 million and used $102.0 million of the proceeds to prepay principal of the 2007 Term Loan in June 2010.

Operating Cash Flow

Net cash used in operations was $42.8 million, $16.9 million and $97.9 million in 2011, 2010 and 2009, respectively. Net cash used in operations related primarily to the general administrative overhead costs, pipeline operations costs and LNG and natural gas marketing overhead, offset by earnings from our LNG and natural gas marketing business. The increase in 2011 compared to 2010 primarily resulted from increased costs incurred to develop the proposed liquefaction project at the Sabine Pass LNG terminal. The decrease in 2010 compared to 2009 primarily resulted from Sabine Pass LNG beginning to receive capacity reservation fee payments from Total and Chevron during 2009.

Repurchases and Prepayments of Debt

In 2010 and 2009, we used $104.7 million and $30.0 million, respectively, of cash and cash equivalents to repay/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 to Cheniere Investments in the second quarter of 2010, we used $2.7 million to partially prepay the 2008 Loans. In the second quarter of 2009, we used a combination of $30.0 million cash and cash equivalents and 4.0 million shares of Cheniere common stock to prepay $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes.

Distributions to Non-controlling Interest Holders

During 2011, 2010 and 2009, Cheniere Partners distributed $28.2 million, $26.4 million and $26.4 million, respectively, to its non-affiliated common unitholders.

Investment in Cheniere Partners

In September 2011, we invested $17.8 million in Cheniere Partners related to our purchase of 1.1 million common units concurrent with an underwritten public offering of 3.0 million common units at a price of $15.25 per common unit. Cheniere Partners is using the net proceeds from the offering for general business purposes, including the development costs of its project to add liquefaction capacity at the Sabine Pass LNG terminal.

LNG Terminal and Pipeline Construction-in-process, net

Capital expenditures for our LNG terminals and pipeline projects were $8.9 million, $4.2 million and $112.3 million in 2011, 2010 and 2009, respectively. The significant decrease in capital expenditures in 2011 and 2010 compared to 2009 is a result of the substantial completion of construction of the Sabine Pass LNG terminal in September 2009.

Purchase of Treasury Shares

During 2011, 2010 and 2009, we used $14.4 million, $2.8 million and $1.0 million, respectively, of cash and cash equivalents to purchase restricted stock that was returned to us by employees to cover taxes related to their restricted stock that vested during the periods.

Investment in Restricted Cash and Cash Equivalents

In 2011, the $15.9 million investment in restricted cash and cash equivalents primarily resulted from Cheniere Partners' public offering in September 2011 in which Cheniere Partners sold 3.0 million common units in an underwritten public offering and 1.1 million common units to us at a price of $15.25 per common unit. Cheniere Partners is using the net proceeds from the offering for general business purposes, including the development costs of its project to add liquefaction capacity at the Sabine Pass LNG terminal.

Debt Agreements

The following table (in thousands) and the explanatory paragraphs following the table summarize our various debt agreements as of December 31, 2011:



	Sabine Pass LNG, L.P.			Cheniere Energy Partners, L.P.		Other Cheniere Energy, Inc.			Consolidated Cheniere Energy, Inc.
Current debt
2007 Term Loan (1)	$	—		$	—	$	298,000		$	298,000
Convertible Senior Unsecured Notes	$	—		$	—	$	204,630		$	204,630
Total current debt	—			—		502,630			502,630
Current debt discount
Convertible Senior Unsecured Notes (2)	—			—		(9,906		)	(9,906		)
Current debt, net of discount	—			—		492,724			492,724

Long-term debt (including related party)
Senior Notes	$	2,215,500		$	—	$	—		$	2,215,500
2008 Loans (including related party)	$	—		$	—	$	282,293		$	282,293
Total long-term debt	2,215,500			—		282,293			2,497,793
Long-term debt discount
Senior Notes (3)	(23,082		)	—		—			(23,082		)
Long-term debt (including related party), net of discount	$	2,192,418		$	—	$	282,293		$	2,474,711


(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.

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 bore interest at a fixed rate of 9¾% per annum. Interest was calculated on the unpaid principal amount of the 2007 Term Loan outstanding and was payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year. The 2007 Term Loan had a maturity date of May 31, 2012. The 2007 Term Loan was secured by a pledge of our 135,383,831 subordinated units in Cheniere Partners.

In May 2010, we sold our 30% limited partner 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. As of December 31, 2010, $298.0 million was outstanding under the 2007 Term Loan and included in long-term debt on our Consolidated Balance Sheets.

During the second quarter of 2011, we reclassified $298.0 million of debt from a long-term liability to a current liability because our 2007 Term Loan was due within 12 months as of May 31, 2011. In January 2012, we repaid the 2007 Term Loan in full.

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 "Convertible Senior Unsecured Notes"). The notes bear interest at a rate of 2¼% per year. The notes are convertible at any time into our common stock under certain circumstances at an initial conversion rate of 28.2326 shares per $1,000 principal amount of the notes, which is equal to a conversion price of approximately $35.42 per share. As of December 31, 2011, no holders had elected to convert their notes at the conversion rate.

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.

During the second quarter of 2009, we reduced debt by exchanging $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes for a combination of $30.0 million cash and cash equivalents and 4.0 million shares of Cheniere common stock, reducing our principal amount due in 2012 to $204.6 million. The remaining principal amount of the Convertible Senior Unsecured Notes are convertible into 5.8 million shares of our common stock.

During the third quarter of 2011, we reclassified $190.7 million of debt, net of discount, from a long-term liability to a current liability because our Convertible Senior Unsecured Notes were due within 12 months as of August 1, 2011.

As discussed in Note 15—"Debt and 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 December 31, 2011, the unamortized debt discount to the Convertible Senior Unsecured Notes was $9.9 million.

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.

Sabine Pass LNG may redeem some or all of the Senior Notes at any time, and from time to time, at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:

•1.0% of the principal amount of the Senior Notes; or

•

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.

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 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. During the years ended December 31, 2011, 2010 and 2009, Sabine Pass LNG made distributions to Cheniere Partners of $313.6 million, $374.8 million and $295.7 million, respectively, after satisfying all of the applicable conditions in the Sabine Pass Indenture.

2008 Loans

In August 2008, we entered into a credit agreement pursuant to which we obtained $250.0 million in convertible term loans ("2008 Loans"). The 2008 Loans have a maturity date in 2018. The 2008 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. The 2008 Loans are secured by Cheniere's rights and fees payable under management services agreements with Sabine Pass LNG and Cheniere Partners, by Cheniere's 12.0 million common units in Cheniere Partners, by the equity and assets of Cheniere's pipeline entities, by the equity of various other subsidiaries and certain other assets and subsidiary guarantees.

In June 2010, the 2008 Loans were amended to permit all funds on deposit in a TUA reserve payment account to be applied to the prepayment of the accrued interest on the loans outstanding under the 2008 Loans, with any remainder to be applied to the prepayment of the principal balance of such 2008 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 of the 2008 Loans.

The outstanding principal amount of the 2008 Loans held by Scorpion Capital Partners, LP ("Scorpion"), the holder of 3.4% of the 2008 Loans as of December 31, 2011, is exchangeable for shares of Cheniere common stock at a price of $5.00 per share pursuant to an amendment to the 2008 Loans adopted in September 2011. No portion of any accrued interest is eligible for exchange into Cheniere common stock. On June 16, 2011, our stockholders approved a proposal to permit Scorpion to exchange its 2008 Loans for common stock, to hold such shares of common stock, and to allow Scorpion to vote the common stock as any other stockholder. The portion of outstanding principal amount of the 2008 Loans for Scorpion is classified as related party long-term debt on our consolidated financial statements because Scorpion is an affiliate of one of Cheniere's directors.

As of December 31, 2011 and December 31, 2010, we classified $9.6 million and $8.9 million, respectively, as part of Long-Term Debt—Related Parties on our Consolidated Balance Sheets because a related party then held these portions of this debt.

Issuances of Common Stock

During 2011, no shares of our common stock were issued pursuant to the exercise of stock options. During 2011, we issued 7.8 million shares of restricted stock to new and existing employees.

During 2010, no shares of our common stock were issued pursuant to the exercise of stock options. During 2010, we issued 1.2 million shares of restricted stock to new and existing employees. We also issued 10.1 million shares of our common stock to the lenders of our 2008 Loans in connection with the December 2010 amendment to the 2008 Loans.

During 2011 and 2010, we raised no proceeds from the exercise of stock options or the exchange or exercise of warrants.

Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2011 (in thousands).



	Payments Due for Years Ended December 31,
	Total		2012		2013-2014		2015-2016		Thereafter
Long-term debt (excluding interest) (1)	$	3,000,423	$	502,630	$	550,000	$	1,665,500	$	282,293
Operating lease obligations (2)(3)	327,271		14,046		27,429		25,601		260,195
Construction and purchase obligations (4)	2,760		2,265		495		—		—
Other obligations (5)	13,149		3,335		4,907		4,907		—
Total	$	3,343,603	$	522,276	$	582,831	$	1,696,008	$	542,488

(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.

In addition, in the ordinary course of business, we maintain letters of credit and have certain cash and cash equivalents restricted in support of certain performance obligations of our subsidiaries. Restricted cash and cash equivalents totaled approximately $185.1 million at December 31, 2011. For more information, see Note 6—"Restricted Cash and Cash Equivalents" of our Notes to Consolidated Financial Statements.

Results of Operations

Overall Operations

2011 vs. 2010

Our consolidated net loss was $198.8 million, or $2.60 per share (basic and diluted), in 2011 compared to a net loss of $76.2 million, or $1.37 per share (basic and diluted), in 2010. This increase in net loss was primarily due to the $128.3 million gain in May 2010 from the sale of our 30% interest in Freeport LNG. In addition, the increase in net loss is a result of increased development expense, increased general and administrative expense ("G&A Expense"), and decreased marketing and trading revenues, which was partially offset by decreased LNG terminal and pipeline operating expenses and decreased interest expense, net.

We recognized one-time charges in 2010 of $128.3 million for a gain on sale of equity method investment and $50.3 million for a loss on early extinguishment of debt. In addition, a portion of our loss was attributable to the recognition of non-cash, share-based payments recognized in the consolidated financial statements based on fair value at the date of grant. As a result of our issuance of non-cash, share-based payments to employees, we recorded $26.4 million and $17.9 million of non-cash compensation expense in 2011 and 2010, respectively. Not including the impact of these one-time charges in 2011 and 2010 and the impact of non-cash expense in 2011 and 2010, our net loss would have been $172.4 million, or $2.25 net loss per common share (basic and diluted), and $136.3 million, or $2.44 net loss per common share (basic and diluted), in 2011 and 2010, respectively.

2010 vs. 2009

Our consolidated net loss was $76.2 million, or $1.37 per share (basic and diluted), in 2010 compared to a net loss of $161.5 million, or $3.13 per share (basic and diluted), in 2009. The decrease in the 2010 net loss was primarily due to a gain in 2010 on the sale of our 30% interest in Freeport LNG, increased LNG terminal revenues as a result of the Sabine Pass LNG terminal starting commercial operations during 2009 that was partially offset by a loss on the early extinguishment of our 2008 Loans, increased LNG terminal and pipeline development and operations and maintenance expense, and increased depreciation, depletion and amortization expense ("DD&A").

A significant portion of our loss was attributable to the recognition of non-cash, share-based payments recognized in the consolidated financial statements based on fair value at the date of grant. As a result of our issuance of non-cash, share-based payments to employees, we recorded $17.9 million and $19.2 million of non-cash compensation expense in 2010 and 2009, respectively. In addition, we recognized one-time charges in 2010 of $128.3 million for a gain on sale of equity method investment and $50.3 million for a loss on early extinguishment of debt. In 2009, we recognized one-time charges of $45.4 million for a gain on early extinguishment of debt. Not including the impact of these one-time charges in 2010 and 2009 and the impact of non-cash expense in 2010 and 2009, our net loss would have been $136.3 million, or $2.44 net loss per common share (basic and diluted), and $187.7 million, or $3.64 net loss per common share (basic and diluted), in 2010 and 2009, respectively.

LNG Terminal Revenues

2011 vs. 2010

LNG terminal revenues increased $4.8 million, from $269.5 million in 2010 to $274.3 million in 2011. This increase is primarily a result of increased LNG export loading fee revenue.

2010 vs. 2009

LNG terminal revenues increased $99.4 million, from $170.1 million in 2009 to $269.5 million in 2010. Of this total increase, $96.9 million was a result of Total and Chevron capacity reservation fee TUA payments beginning on April 1, 2009 and July 1, 2009, respectively. The remaining increase in LNG terminal revenues is a result of increased revenues earned from our 2% retainage and LNG export cargo loading fees charged to customers in 2010.

LNG and Natural Gas Marketing and Trading Revenues

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 the table below (in thousands) for an itemized comparison of each major type of energy trading and risk management activity:



	Years Ended December 31,
	2011			2010		2009
Physical LNG and natural gas sales, net of costs	$	9,909		$	6,724	$	2,296
Inventory lower-of-cost-or-market write-downs	(10,820		)	—		(3,323		)
Gain from derivatives	2,475			2,265		8,606
Other energy trading activities	11,990			10,033		508
Total LNG and natural gas marketing revenues	$	13,554		$	19,022	$	8,087

2011 vs. 2010

LNG and natural gas marketing and trading revenues decreased $5.4 million, from $19.0 million in 2010 to $13.6 million in 2011. The $5.4 million decrease in marketing and trading revenues is primarily a result of lower-of-cost-or-market adjustments on our LNG inventory in 2011. Other energy trading activities primarily consist of our agreements with LNGCo that became effective on April 1, 2010. During 2011 and 2010, we recognized $12.0 million and $10.1 million, respectively, of marketing and trading revenues from LNGCo.

2010 vs. 2009

LNG and natural gas marketing and trading revenues increased $10.9 million, from $8.1 million in 2009 to $19.0 million in 2010. The $8.1 million in 2009 primarily resulted from $8.6 million in derivative gains and $2.3 million of net revenue from physical sales of regasified LNG, which was offset by a $3.3 million inventory write-down. The $19.0 million of LNG and natural gas marketing and trading revenues in 2010 primarily resulted from fixed fee and gross margin revenue from LNGCo and physical sales of LNG.

General and Administrative Expense

Our G&A Expense includes costs that are incurred for general corporate purposes, LNG and natural gas marketing activities, the Sabine Pass LNG terminal and Creole Trail Pipeline activities.

2011 vs. 2010

G&A Expense increased $19.8 million, from $68.6 million in 2010 to $88.4 million in 2011. This increase primarily resulted from increased salary and non-cash compensation expense related to an increased number of corporate employees.

Depreciation, Depletion and Amortization

2010 vs. 2009

DD&A increased $9.1 million, from $54.2 million in 2009 to $63.3 million in 2010. This increase primarily resulted from the substantial completion of construction and achievement of full operability of the Sabine Pass LNG 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.

LNG Terminal and Pipeline Operating Expense

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

2011 vs. 2010

LNG terminal and pipeline operating expense decreased $3.3 million, from $42.4 million in 2010 to $39.1 million in 2011. This decrease primarily resulted from decreased fuel costs in 2011 as a result of efficiencies in our LNG inventory management.

2010 vs. 2009

LNG terminal and pipeline operating expense increased $5.5 million, from $36.9 million in 2009 to $42.4 million in 2010. This $5.5 million increase primarily resulted from the achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009 (as described above).

LNG Terminal and Pipeline Development Expense

Our LNG terminal and pipeline development expenses include primarily professional costs associated with front-end engineering and design work, obtaining regulatory approvals authorizing construction of our facilities and other required permitting for our planned LNG terminals and natural gas pipelines.

2011 vs. 2010

LNG terminal and pipeline development expenses increased $28.8 million, from $12.0 million in 2010 to $40.8 million in 2011. This increase resulted from costs incurred to develop the proposed liquefaction project at the Sabine Pass LNG terminal.

2010 vs. 2009

LNG terminal and pipeline development expenses increased $11.8 million from $0.2 million in 2009 compared to $12.0 million in 2010. The increase resulted from liquefaction development activities at the Sabine Pass LNG terminal in 2010. The 2009 costs primarily related to continued site maintenance costs incurred with respect to our potential Corpus Christi and Creole Trail LNG terminal projects.

Gain on Sale of Equity Method Investment

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

Interest Expense, net

2011 vs. 2010

Interest expense, net of amounts capitalized, decreased $2.6 million, from $262.0 million in 2010 to $259.4 million in 2011. This decrease in interest expense resulted from the reduction of our indebtedness during the second quarter of 2010.

2010 vs. 2009

Interest expense, net of amounts capitalized, increased $18.7 million, from $243.3 million in 2009 to $262.0 million in 2009. The increase in interest expense resulted from the achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009, which reduced the amount of interest expense that was capitalized.

Gain/(Loss) on Early Extinguishment of Debt

2011 vs. 2010

Gain/(Loss) on early extinguishment of debt decreased $50.3 million, from a $50.3 million loss in 2010 to zero in 2011. During the fourth quarter of 2010, the 2008 Loans were amended to, among other things: eliminate the "put right," 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 us 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 of 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. As part of the amendments to the 2008 Loans, we issued 10.1 million shares of Cheniere common stock to such lenders. The value of the 10.1 million Cheniere common shares were expensed as a loss on early extinguishment of debt in the fourth quarter of 2010.

2010 vs. 2009

Gain/(Loss) on early extinguishment of debt decreased $95.7 million, from a $45.4 million gain in 2009 to a $50.3 million loss in 2010. The $50.3 million loss in 2010 is discussed above. During the second quarter of 2009, we reduced debt by exchanging $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes for a combination of $30.0 million cash and cash equivalents and 4.0 million common shares, reducing our principal amount due in 2012 to $204.6 million. As a result of the exchange, we recognized a gain of $45.4 million that was reported as a gain on early extinguishment of debt in 2009.

Off-Balance Sheet Arrangements

As of December 31, 2011, we had no "off-balance sheet arrangements" that may have a current or future material affect on our consolidated financial position or results of operations.

Inflation and Changing Prices

During the years ended December 31, 2011, 2010 and 2009, inflation and changing commodity prices have had an impact on our oil and gas revenues but have not significantly impacted our results of operations.

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 generally accepted accounting principles in the United States ("GAAP"), we endeavor to comply 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.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Accounting for LNG Activities

Generally, we begin capitalizing the costs of our LNG 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 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 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 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 GAAP 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 cash flows attributable to the future sale of LNG inventory and to hedge the price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal. We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 16—"Financial Instruments" of our Notes to Consolidated Financial Statements

Gains and losses in positions to hedge the cash flows attributable to the future sale of LNG inventory are classified as marketing and trading revenues on our Consolidated Statements of Operations. Gains or losses in the positions to mitigate the price risk from future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal are classified as derivative gain (loss), net on our Consolidated Statements of Operations. We record changes in the fair value of our derivative positions 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 similar assets or liabilities. 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 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 December 31, 2011 and 2010, attributable to our LNG 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 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 years ended December 31, 2011 and 2010 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 18—"Share-Based Compensation" of our Notes to Consolidated Financial Statements).

Recent Accounting Standards

In June 2011, the Financial Accounting Standards Board ("FASB") amended current comprehensive income guidance. The amended guidance eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, we must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. This guidance will be effective for public companies during the interim and annual periods beginning after December 15, 2011 with early adoption permitted. Also, in December 2011, FASB issued an accounting standard update to abrogate the requirement for presentation in the income statement of the effect on net income of reclassification adjustments out of AOCI as required in FASB's June 2011 amendment. We expect to adopt this guidance in our first fiscal quarter ending March 31, 2012. The adoption of this guidance will not have an impact on our consolidated financial position, results of operations or cash flows as it only requires a change in the format of the current presentation.

In September 2011, the FASB amended the guidance on the annual testing of goodwill for impairment. The amended guidance will allow companies to assess qualitative factors to determine if it is more-likely-than-not that goodwill might be impaired and whether it is necessary to perform the two-step goodwill impairment test required under current accounting standards. This guidance will be effective for our fiscal year ending December 31, 2012, with early adoption permitted. We adopted this guidance in our fourth fiscal quarter ended December 31, 2011. The adoption of this guidance did not have a material impact on our consolidated financial position, results of operations or cash flows.

ITEM 7A. 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

We have entered into certain derivative instruments to economically hedge the price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal ("Fuel Derivatives") and to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory ("LNG Inventory Derivatives"). We use one-day value at risk ("VaR") with a 95% confidence interval and other methodologies for market risk measurement and control purposes. The VaR is calculated using the Monte Carlo simulation method. The table below provides information about our derivative financial instruments that are sensitive to changes in natural gas prices as of December 31, 2011 (in thousands, except for volume and price range data).



Hedge Description	Hedge Instrument	Contract Volumes (MMBtu)	Price Range ($/MMBtu)	Final Hedge Maturity Date	Fair Value ($)			VaR ($)
LNG Inventory Derivatives	Fixed price natural gas swaps	1,747,500	$3.124 — $4.465	June 2012	$	1,951		$	12
Fuel Derivatives	Fixed price natural gas swaps	1,065,000	3.997 — 5.002	January 2013	(1,415		)	84

We had not entered into any natural gas or foreign currency derivative positions as of December 31, 2010.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES




Management’s Reports to the Stockholders of Cheniere Energy, Inc.	54
Reports of Independent Registered Public Accounting Firm—Ernst & Young LLP	55
Consolidated Balance Sheets	57
Consolidated Statements of Operations	58
Consolidated Statements of Stockholders’ (Deficit) Equity	59
Consolidated Statements of Cash Flows	60
Notes to Consolidated Financial Statements	61
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data	87

MANAGEMENT’S REPORTS TO THE STOCKHOLDERS OF CHENIERE ENERGY, INC.

Management’s Report on Internal Control Over Financial Reporting

As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Cheniere Energy, Inc. and its subsidiaries ("Cheniere"). In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Cheniere’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.

Based on our assessment, we have concluded that Cheniere maintained effective internal control over financial reporting as of December 31, 2011, based on criteria in Internal Control—Integrated Framework issued by the COSO.

Cheniere’s independent auditors, Ernst & Young LLP, have issued an audit report on Cheniere’s internal control over financial reporting as of December 31, 2011, which is contained in this Form 10-K.

Management’s Certifications

The certifications of Cheniere’s Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere’s Form 10-K.

CHENIERE ENERGY, INC.




By:	/s/ CHARIF SOUKI	By:	/s/ MEG A. GENTLE
	Charif Souki Chief Executive Officer and President (Principal Executive Officer)		Meg A. Gentle Senior Vice President and Chief Financial Officer (Principal Financial Officer)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

Cheniere Energy, Inc.

We have audited the accompanying consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders' (deficit) equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cheniere Energy, Inc. and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cheniere Energy, Inc.'s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2012 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

February 24, 2012

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

Cheniere Energy, Inc.

We have audited Cheniere Energy, Inc. and subsidiaries' internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Cheniere Energy, Inc. and subsidiaries' management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Cheniere Energy, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders' (deficit) equity, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 24, 2012 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

February 24, 2012

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)



	December 31,
	2011			2010
ASSETS
Current assets
Cash and cash equivalents	$	459,160		$	74,161
Restricted cash and cash equivalents	102,165			73,062
Accounts and interest receivable	3,043			4,699
LNG inventory	6,562			1,212
Prepaid expenses and other	20,522			12,476
Total current assets	591,452			165,610

Non-current restricted cash and cash equivalents	82,892			82,892
Property, plant and equipment, net	2,107,129			2,157,597
Debt issuance costs, net	33,356			41,656
Goodwill	76,819			76,819
Intangible LNG assets	4,782			6,067
Other	18,895			22,866
Total assets	$	2,915,325		$	2,553,507

LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities
Current debt, net of discount	$	492,724		$	—
Accrued liabilities	63,074			38,459
Deferred revenue	26,628			26,592
Accounts payable	1,103			1,283
Other	1,431			—
Total current liabilities	584,960			66,334

Long-term debt, net of discount	2,465,113			2,918,579
Long-term debt-related parties, net of discount	9,598			8,930
Long-term deferred revenue	25,500			29,994
Other non-current liabilities	3,146			2,280

Commitments and contingencies


Stockholders' deficit
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued	—			—
Common stock, $0.003 par value
Authorized: 240.0 million shares at December 31, 2011 and 2010
Issued and outstanding: 129.5 million and 67.8 million shares at December 31, 2011 and 2010, respectively	389			204
Treasury stock: 3.4 million and 1.5 million shares at December 31, 2011 and 2010, respectively, at cost	(20,195		)	(4,338		)
Additional paid-in-capital	898,702			404,125
Accumulated deficit	(1,260,205		)	(1,061,449		)
Accumulated other comprehensive income	(258		)	(173		)
Total stockholders' deficit	(381,567		)	(661,631		)
Non-controlling interest	208,575			189,021
Total deficit	(172,992		)	(472,610		)
Total liabilities and deficit	$	2,915,325		2,553,507

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)



	Year Ended December 31,
	2011			2010			2009
Revenues
LNG terminal revenues	$	274,272		$	269,538		$	170,071
Marketing and trading revenues	13,554			19,022			8,087
Oil and gas sales	2,568			2,858			2,866
Other	50			95			102
Total revenues	290,444			291,513			181,126

Operating costs and expenses
General and administrative expense	88,427			68,626			65,830
Depreciation, depletion and amortization	63,405			63,251			54,229
LNG terminal and pipeline operating expense	39,101			42,415			36,857
LNG terminal and pipeline development expense	40,803			11,971			223
Other	562			627			491
Total operating costs and expenses	232,298			186,890			157,630
Income from operations	58,146			104,623			23,496

Other income (expense)
Interest expense, net	(259,393		)	(262,046		)	(243,295		)
Gain (loss) on early extinguishment of debt	—			(50,320		)	45,363
Gain on sale of equity method investment	—			128,330			—
Derivative gain (loss)	(2,251		)	461			5,277
Other income	320			558			1,504
Total other expense	(261,324		)	(183,017		)	(191,151		)
Loss before income taxes and non-controlling interest	(203,178		)	(78,394		)	(167,655		)
Income tax provision	(160		)	—			—
Loss before non-controlling interest	(203,338		)	(78,394		)	(167,655		)
Non-controlling interest	4,582			2,191			6,165
Net loss	$	(198,756	)	$	(76,203	)	$	(161,490	)

Net loss per share attributable to common stockholders - basic and diluted	$	(2.60	)	$	(1.37	)	$	(3.13	)
Weighted average number of common shares outstanding - basic and diluted	76,483			55,765			51,598

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ (DEFICIT) EQUITY

(in thousands)



	Total Stockholders' (Deficit) Equity
	Common Stock					Treasury Stock				Additional Paid-in Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Non- controlling Interest			Total (Deficit) Equity
	Shares		Amount			Shares	Amount			Additional Paid-in Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Non- controlling Interest			Total (Deficit) Equity
Balance—December 31, 2008	52,297		$	157		179	$	(496	)	$	300,033		$	(823,756	)	$	(154	)	$	250,162		$	(274,054	)
Issuances of stock	3,985		12			—	—			16,212			—			—			—			16,224
Issuances of restricted stock	886		3			—	—			(3		)	—			—			—			—
Forfeitures of restricted stock	(89	)	—			89	—			—			—			—			—			—
Stock-based compensation	—		—			—	—			20,728			—			—			—			20,728
Treasury stock acquired	(428	)	(2		)	429	(998		)	1			—			—			—			(999		)
Comprehensive gain: Foreign currency translation	—		—			—	—			—			—			21			—			21
Loss attributable to non-controlling interest	—		—			—	—			—			—			—			(6,165		)	(6,165		)
Distribution to non-controlling interest	—		—			—	—			—			—			—			(26,392		)	(26,392		)
Net loss	—		—			—	—			—			(161,490		)	—			—			(161,490		)
Balance—December 31, 2009	56,651		170			697	(1,494		)	336,971			(985,246		)	(133		)	217,605			(432,127		)
Issuances of stock	10,125		31			—	—			49,278			—			—			—			49,309
Issuances of restricted stock	1,751		4			—	—			(5		)	—			—			—			(1		)
Forfeitures of restricted stock	(161	)	—			161	—			—			—			—			—			—
Stock-based compensation	—		—			—	—			17,878			—			—			—			17,878
Treasury stock acquired	(605	)	(1		)	605	(2,844		)	3			—			—			—			(2,842		)
Comprehensive loss: Foreign currency translation	—		—			—	—			—			—			(40		)	—			(40		)
Loss attributable to non-controlling interest	—		—			—	—			—			—			—			(2,191		)	(2,191		)
Distribution to non-controlling interest	—		—			—	—			—			—			—			(26,393		)	(26,393		)
Net loss	—		—			—	—			—			(76,203		)	—			—			(76,203		)
Balance—December 31, 2010	67,761		204			1,463	(4,338		)	404,125			(1,061,449		)	(173		)	189,021			(472,610		)
Issuances of stock	55,845		168				—			468,230			—			—			—			468,398
Issuances of restricted stock	7,827		23			—	—			(23		)	—			—			—			—
Forfeitures of restricted stock	(39	)	—			39	—			—			—			—			—			—
Stock-based compensation	—		—			—	—			26,364			—			—			—			26,364
Treasury stock acquired	(1,884	)	(6		)	1,884	(15,857		)	6			—			—			—			(15,857		)
Comprehensive loss: Foreign currency translation	—		—			—	—			—			—			(85		)	—			(85		)
Loss attributable to non-controlling interest	—		—			—	—			—			—			—			(4,582		)	(4,582		)
Sale of common units to non-controlling interest	—		—			—	—			—			—			—			52,351			52,351
Distribution to non-controlling interest	—		—			—	—			—			—			—			(28,215		)	(28,215		)
Net loss	—		—			—	—			—			(198,756		)	—			—			(198,756		)
Balance—December 31, 2011	129,510		$	389		3,386	$	(20,195	)	$	898,702		$	(1,260,205	)	$	(258	)	$	208,575		$	(172,992	)

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2011			2010			2009
Cash flows from operating activities
Net loss	$	(198,756	)	$	(76,203	)	$	(161,490	)
Adjustments to reconcile net loss to net cash used in operating activities:
Gain on sale of limited partnership investment	—			(128,330		)	—
Depreciation, depletion and amortization	63,405			63,251			54,229
(Gain)/loss on early extinguishment of debt	—			50,320			(45,363		)
Non-cash interest expense on 2008 Loans	19,636			32,523			32,321
Use of cash for accrued interest	—			(60,899		)	—
Amortization of debt issuance and discount costs	28,677			27,185			27,549
Non-cash compensation	26,364			17,839			19,204
Non-cash LNG inventory write-downs	10,992			264			3,516
Non-controlling interest	(4,582		)	(2,191		)	(6,165		)
Use of restricted cash and cash equivalents	4,616			30,823			1,353
Other	1,413			(7,095		)	(147		)
Changes in operating assets and liabilities:
Accounts and interest receivable	1,463			466			(1,343		)
Accounts payable and accrued liabilities	28,857			3,035			253
LNG inventory	(16,342		)	31,126			(32,628		)
Deferred revenue	(4,458		)	(3,864		)	19,956
Prepaid expenses and other	(4,049		)	4,830			(9,102		)
Net cash used in operating activities	(42,764		)	(16,920		)	(97,857		)

Cash flows from investing activities
Proceeds from sale of limited partnership investment	—			104,330			—
Investment in Cheniere Partners	(17,806		)	—			—
LNG terminal and pipeline construction-in-process, net	(8,934		)	(4,223		)	(112,317		)
Use of restricted cash and cash equivalents	8,222			5,350			110,399
Distributions from limited partnership investment	—			3,900			15,300
Other	(3,613		)	(371		)	(1,398		)
Net cash provided by (used in) investing activities	(22,131		)	108,986			11,984

Cash flows from financing activities
Sale of common stock, net	468,598			—			—
Sale of common units by Cheniere Partners	52,351			—			—
Use of (investment in) restricted cash and cash equivalents	(24,136		)	29,073			130,702
Repurchases and prepayments of debt	—			(104,681		)	(30,030		)
Distributions to non-controlling interest	(28,215		)	(26,393		)	(26,392		)
Purchase of treasury shares	(14,363		)	(2,844		)	(999		)
Other	(4,341		)	(1,432		)	(1,228		)
Net cash provided by (used in) financing activities	449,894			(106,277		)	72,053

Net increase (decrease) in cash and cash equivalents	384,999			(14,211		)	(13,820		)
Cash and cash equivalents—beginning of period	74,161			88,372			102,192
Cash and cash equivalents—end of period	$	459,160		$	74,161		$	88,372

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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

Cheniere Energy, Inc., a Delaware corporation, is a Houston-based energy company primarily engaged in liquefied natural gas ("LNG") related businesses. We own and operate the Sabine Pass LNG terminal in Louisiana through our 88.8% ownership interest in and management agreements with Cheniere Energy Partners, L.P. ("Cheniere Partners"), which is a publicly traded partnership that we created in 2007. We also own and operate the Creole Trail Pipeline, which interconnects the Sabine Pass LNG terminal with natural gas markets in North America. One of our subsidiaries, Cheniere Marketing, LLC ("Cheniere Marketing"), is marketing LNG and natural gas on its own behalf and on behalf of Cheniere Partners, is working to monetize LNG storage and regasification capacity reserved by Cheniere Partners at the Sabine Pass LNG terminal. Cheniere Partners is developing a project to add liquefaction capabilities at the Sabine Pass LNG terminal. We are in various stages of developing projects, including LNG terminal and pipeline related projects, each of which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision. Unless the context requires otherwise, references to the "Company", "Cheniere", "we", "us" and "our" refer to Cheniere Energy, Inc. and its subsidiaries, including our publicly traded subsidiary partnership, Cheniere Partners.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Consolidated Financial Statements were prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The consolidated financial statements include the accounts of Cheniere Energy, Inc. and its majority-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

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

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Accounting for LNG Activities

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 terminal is recognized as revenues as Sabine Pass LNG , L.P. ("Sabine Pass LNG"), a subsidiary of Cheniere Partners, performs the services set forth in each customer’s TUA.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

LNG and Natural Gas Marketing

Purchase of LNG and natural gas

Transportation contracts

Derivatives

Gains and losses in positions to hedge the cash flows attributable to the future sale of LNG inventory are classified as marketing and trading revenues on our Consolidated Statements of Operations. Gains or losses in the positions to mitigate the price risk from future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal are classified as derivative gain (loss) on our Consolidated Statements of Operations. We record changes in the fair value of our derivative positions 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 similar assets or liabilities. 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 ("the 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 accounting principles generally accepted in the United States of America ("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

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

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.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments are capitalized, while expenditures for maintenance and repairs and general and administrative activities are charged to expense as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in operations.

Management reviews property, plant and equipment for impairment periodically and whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. We have recorded no significant impairments related to fixed assets for 2011, 2010 or 2009.

Income Taxes

Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the tax basis of assets and liabilities and their reported amounts in the consolidated financial statements. Deferred tax assets and liabilities are included in the consolidated financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period's provision for income taxes. A valuation allowance is provided for deferred tax assets if it is more likely than not that such asset will not be realizable.

Use of Estimates

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

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

Cash Equivalents

We classify all investments with original maturities of three months or less as cash equivalents. Our investments are primarily in commercial paper and are made in accordance with corporate policy, which, among other things, stipulates minimum acceptable credit ratings of commercial paper issuers.

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, restricted cash and cash equivalents, restricted certificates of deposit, accounts receivable, and accounts payable approximate fair value because of the short maturity of those instruments. We use available market data and valuation methodologies to estimate the fair value of debt.

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. We maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

Goodwill

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Debt Issuance Costs

Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and printing costs. These costs are capitalized and are being amortized to interest expense over the term of the related debt facility.

Share-Based Compensation Expense

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 years ended December 31, 2011 and 2010 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's 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 18—"Share-Based Compensation" of our Notes to Consolidated Financial Statements).

Net Loss Per Share

Net loss per share ("EPS") is computed in accordance with GAAP. Basic EPS excludes dilution and is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted EPS reflects potential dilution and is computed by dividing net income 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. Basic and diluted EPS for all periods presented are the same since the effect of our options, warrants and unvested stock is anti-dilutive to our net loss per share. Stock options, warrants and unvested stock representing securities that could potentially dilute basic EPS in the future that were not included in the diluted computation because they would have been anti-dilutive for the years 2011, 2010 and 2009, were 2.4 million shares, 5.8 million shares and 9.0 million shares, respectively. Common shares of 7.5 million on a weighted average basis, issuable upon conversion of the 2008 Loans and the Convertible Senior Unsecured Notes (described in Note 15—"Debt and Debt—Related Parties"), were not included in the computation of diluted net loss per share for 2011 and 2010, because the computation of diluted net loss per share utilizing the "if-converted" method would be anti-dilutive. In addition, common shares of 59.2 million on a weighted average basis, issuable upon conversion of the 2008 Loans and the Convertible Senior Unsecured Notes, were not included in the computation of diluted net loss per share for 2009 because the computation of diluted net loss per share utilizing the "if-converted" method would be anti-dilutive. No adjustments were made to reported net loss in the computation of EPS.

Asset Retirement Obligations

We recognize asset retirement obligations ("AROs") for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset. Our recognition of asset retirement obligations is described below:

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Natural Gas Pipeline

Currently, the Creole Trail Pipeline is our only constructed and operating natural gas pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline have no stipulated termination dates. Therefore, we have concluded that due to advanced technology associated with current natural gas pipelines and our intent to operate the Creole Trail Pipeline as long as supply and demand for natural gas exists in the United States, we have not recorded an ARO associated with the Creole Trail Pipeline.

LNG Terminal

Currently, the Sabine Pass LNG terminal is our only constructed and operating LNG terminal. Based on the real property lease agreements at the Sabine Pass LNG terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewal options. Due to the language in the real property lease agreements, we have determined that the cost to surrender the LNG terminal in the required condition will be minimal, and therefore have not recorded an ARO associated with the Sabine Pass LNG terminal.

Recent Accounting Standards Not Yet Adopted

NOTE 3—Liquidity

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

NOTE 4—CHENIERE ENERGY PARTNERS, L.P.

As of December 31, 2011, our combined general partner and limited partner ownership interest in Cheniere Partners was approximately 88.8%. As of such date, we held 135,383,831 subordinated units, 11,963,488 common units and a 2% general partner interest in Cheniere Partners.

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

Cheniere Partners' cash distribution policy is consistent with the terms of its partnership agreement, which requires that it distribute all of its available cash quarterly. During the subordination period, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the initial quarterly distribution of $0.425 per quarter, plus any arrearages in the payment of the initial quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. At December 31, 2011, we owned all of the outstanding subordinated units, representing 81% of the limited partner interest in Cheniere Partners. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until after the common units have received the initial quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordination period is to increase the likelihood that during this period there will be sufficient available cash to pay the initial quarterly distributions on the common units.

NOTE 5—NON-CONTROLLING INTEREST

We have consolidated certain partnerships because we have a controlling interest in these ventures. Therefore, the entities’ financial statements are consolidated in our Consolidated Financial Statements and the entities’ other equity is recorded as a non-controlling interest. The following table sets forth the components of our non-controlling interest balance since inception attributable to third-party investors’ interests at December 31, 2011 (in thousands):



Net proceeds from Cheniere Partners’ issuance of common units (1)	$	150,793
Net proceeds from Holdings’ sale of Cheniere Partners common units (2)	203,946
Distributions to Cheniere Partners’ non-controlling interest (3)	(121,023		)
Non-controlling interest share of loss of Cheniere Partners	(25,141		)
Non-controlling interest at December 31, 2011	$	208,575

(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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

In January 2011, Cheniere Partners initiated an at-the-market program to sell up to 1.0 million common units, the proceeds from which would be used primarily to fund development costs associated with its proposed liquefaction project. As of December 31, 2011, Cheniere Partners had sold 0.5 million common units with net proceeds of $9.0 million.

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 at a price of $15.25 per common unit. Cheniere Partners received net proceeds of $43.3 million and $16.4 million from the public offering and Cheniere Common Units Holding, LLC sale, respectively.

(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.

NOTE 6—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 has consummated private offerings of an aggregate principal amount of $2,215.5 million of Senior Notes (See Note 15—"Debt and 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, including that 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.

As of December 31, 2011 and 2010, we classified $13.7 million as current restricted cash and cash equivalents for the payment of interest due within twelve months. As of December 31, 2011 and 2010, we classified the permanent debt service reserve fund of $82.4 million as non-current restricted cash and cash equivalents. These cash accounts are controlled by a collateral trustee, and, therefore, are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets.

Other Restricted Cash and Cash Equivalents

As of December 31, 2011 and 2010, $81.4 million and $53.3 million, respectively, of current restricted cash and cash equivalents was primarily related to cash and cash equivalents held by Sabine Pass LNG and Cheniere Partners that were considered restricted to Cheniere. As of December 31, 2011 and 2010, due to various other contractual restrictions, $6.4 million and $6.1 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

NOTE 7—LEASES

During the years ended December 31, 2011, 2010 and 2009, we recognized rental expense for all operating leases of $11.5 million, $10.2 million and $11.3 million, respectively.

Future Annual Minimum Lease Payments

Future annual minimum lease payments, excluding inflationary adjustments, are as follows (in thousands):



Years Ending December 31,	Operating Leases (2) (3)
2012	$	14,046
2013	14,242
2014	13,188
2015	12,764
2016	12,837
Thereafter (1)	260,195
Total	$	327,272


(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.

Tug Boat Agreements

Sabine Pass Tug Services, LLC ("Tug Services"), Cheniere Partners' wholly owned subsidiary, entered into a Marine Services Agreement (the "Tug Agreement") for the use of tug boats and marine services for the Sabine Pass LNG terminal. The term of the Tug Agreement commenced in January 2008 for a period of 10 years, with an option to renew two additional, consecutive terms of five years each. In accordance with accounting literature on how to determine whether an arrangement contains a lease, we determined that the Tug Agreement contains a lease for the tugs specified in the Tug Agreement. In addition, we concluded that the tug boat lease contained in the Tug Agreement is an operating lease, and as such, the equipment component of the Tug Agreement is charged to expense over the term of the Tug Agreement as it becomes payable.

In the second quarter of 2009, Tug Services entered into a Tug Sharing Agreement with Sabine Pass LNG's three TUA customers to provide their LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal and effectively offset the cost of the tug boat lease. The Tug Sharing Agreement provides for each of our customers to pay Tug Services an annual service fee.

LNG Site Leases

Our obligations under LNG site options are renewable on an annual or semiannual basis. We may terminate our obligations at any time by electing not to renew or by exercising the options.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

In January 2005, we exercised our options and entered into three land leases for the site of the Sabine Pass LNG terminal. The leases have an initial term of 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. In February 2005, two of the three leases were amended, thereby increasing the total acreage under lease to 853 acres and increasing the annual lease payments to $1.5 million. In November and December 2011, we entered into two additional land leases, thereby increasing the total acreage under lease to 1,015 acres and increasing the annual lease payments by $0.4 million. The annual lease payments will be adjusted for inflation based on a consumer price index, as defined in the lease agreements, every five years. We recognized $1.8 million, $1.7 million and $1.5 million of site lease expense on our Consolidated Statements of Operations in 2011, 2010 and 2009, respectively.

NOTE 8—VARIABLE INTEREST ENTITY

NOTE 9—LNG INVENTORY

LNG inventory is recorded at cost and is subject to lower of cost or market ("LCM") adjustments at the end of each period. LNG 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 December 31, 2011, we had 1,995,000 MMBtu of LNG inventory recorded at $6.6 million, and as of December 31, 2010, we had 326,000 MMBtu of LNG inventory recorded at $1.2 million on our Consolidated Balance Sheets. During the years ended December 31, 2011, 2010 and 2009, we recognized $11.0 million, $0.3 million and $3.5 million, respectively, as a result of LCM adjustments to our LNG inventory.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

NOTE 10—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists 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):



	December 31,
	2011			2010
LNG terminal costs
LNG terminal	$	1,647,107		$	1,638,811
LNG terminal construction-in-process	39,010			39,393
LNG site and related costs, net	4,982			3,362
Accumulated depreciation	(125,108		)	(82,246		)
Total LNG terminal costs, net	$	1,565,991		$	1,599,320

Natural gas pipeline costs
Natural gas pipeline	$	564,021		$	563,715
Natural gas pipeline construction-in-process	2,427			2,484
Pipeline right-of-ways	18,455			18,455
Accumulated depreciation	(52,878		)	(37,939		)
Total natural gas pipeline costs	$	532,025		$	546,714

Oil and gas properties, successful efforts method
Proved	$	4,170		$	3,872
Accumulated depreciation, depletion and amortization	(3,033		)	(2,604		)
Total oil and gas properties, net	$	1,137		$	1,268

Fixed assets
Computer and office equipment	$	5,952		$	5,472
Furniture and fixtures	4,057			4,509
Computer software	12,601			12,526
Leasehold improvements	7,318			7,318
Other	1,892			1,453
Accumulated depreciation	(23,844		)	(20,983		)
Total fixed assets, net	$	7,976		$	10,295
Property, plant and equipment, net	$	2,107,129		$	2,157,597

LNG Terminal Costs

We began depreciating equipment and facilities associated with the initial 2.6 Bcf/d of sendout capacity and 10.1 Bcf of storage capacity of the Sabine Pass LNG terminal when they were ready for use in the third quarter of 2008. We began depreciating equipment and facilities associated with the remaining 1.4 Bcf/d of sendout capacity and 6.8 Bcf of storage capacity of the Sabine Pass LNG terminal when they were ready for use in the third quarter of 2009. Depreciation expense related to the Sabine Pass LNG terminal totaled $42.6 million, $41.8 million and $32.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

The Sabine Pass LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 15 and 50 years, as follows:



Components		Useful life (yrs)
LNG storage tanks		50
Marine berth, electrical, facility and roads		35
Regasification processing equipment (recondensers, vaporization, and vents)		30
Sendout pumps		20
Other		15-30

In March 2006, our Corpus Christi LNG terminal project satisfied the criteria for capitalization. Accordingly, costs associated with the initial site work for the Corpus Christi LNG terminal have been capitalized. As of December 31, 2011, $35.5 million of costs associated with the initial site work for the Corpus Christi LNG terminal were capitalized as LNG terminal construction-in-process. As noted in Note 2—"Summary of Significant Accounting Policies," management reviews property, plant and equipment for impairment periodically and whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Management’s assessment is based on certain estimates and assumptions used to determine if impairment is warranted. If the estimates and assumptions used are determined to be different in the future, the amount capitalized may be subject to impairment.

Natural Gas Pipeline Costs

Our natural gas pipeline business is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. 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 our 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.

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.

NOTE 11—DEBT ISSUANCE COSTS

We have incurred debt issuance costs in connection with our debt. These costs are capitalized and are being amortized over the term of the related debt. The amortization of the debt issuance cost was recorded as interest expense. As of December 31, 2011, we had capitalized $33.4 million of costs directly associated with the arrangement of debt financing, net of accumulated amortization, as follows (in thousands):



Debt	Debt Issuance Costs		Amortization Period	Accumulated Amortization			Net Costs
2013 Senior Notes	$	9,353	7 years	$	(6,837	)	$	2,516
2016 Senior Notes	30,057		10 years	(14,951		)	15,106
2007 Term Loan	8,450		5 years	(7,925		)	525
2008 Loans	21,293		10 years	(6,377		)	14,916
Convertible Senior Unsecured Notes	5,608		7 years	(5,315		)	293
Total	$	74,761		$	(41,405	)	$	33,356

Scheduled amortization of these debt issuance costs for the next five years is estimated to be $29.6 million.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

NOTE 12—GOODWILL

Our goodwill on our Consolidated Balance Sheets as of December 31, 2011 and 2010 is associated with our LNG terminal reporting unit. We performed our annual goodwill impairment review in the fourth quarters of 2011, 2010 and 2009. In 2011, this impairment review consisted of assessing qualitative factors to determine if it is more-likely-than-not that goodwill might be impaired. In 2010 and 2009, this impairment review consisted of comparing the carrying value, including goodwill, of the reporting unit under review to the estimated fair value of the reporting unit. Had the carrying value exceeded the estimated fair value of the reporting unit, an impairment of the reporting unit would have been recognized, resulting in an impairment charge to earnings. A reporting unit is defined as a business segment or component of a business segment that has similar economic characteristics. For our impairment reviews, we have designated our LNG terminal business as the reporting unit under review due to similar economic characteristics. Our reviews indicated that no impairment of goodwill was necessary.

NOTE 13—ACCRUED LIABILITIES

As of December 31, 2011 and 2010, accrued liabilities consisted of the following (in thousands):



	December 31,
	2011		2010
Accrued interest expense and related fees	$	35,884	$	15,732
Payroll	19,321		11,466
LNG liquefaction costs	1,702		1,402
Debt issuance cost	—		4,101
LNG terminal costs	1,122		1,953
Other accrued liabilities	5,045		3,805
Accrued liabilities	$	63,074	$	38,459

NOTE 14—DEFERRED REVENUE

As of December 31, 2011 and 2010, we had recorded $26.6 million and $26.6 million, respectively, as current deferred revenue and $25.5 million and $30.0 million, respectively, as non-current deferred revenue related to advance capacity reservation fee payments on our Consolidated Balance Sheets.

Advance Capacity Reservation Fee

In November 2004, Total Gas and Power North America, Inc. ("Total") paid Sabine Pass LNG a nonrefundable advance capacity reservation fee of $10.0 million in connection with the reservation of approximately 1.0 Bcf/d of LNG regasification capacity at the Sabine Pass LNG terminal. An additional advance capacity reservation fee payment of $10.0 million was paid by Total to Sabine Pass LNG in April 2005. The advance capacity reservation fee payments are being amortized as a reduction of Total’s regasification capacity reservation fee under its TUA over a 10-year period beginning with the commencement of its TUA on April 1, 2009. As a result, we recorded the advance capacity reservation fee payments that Sabine Pass LNG received, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

In November 2004, Sabine Pass LNG also entered into a TUA to provide Chevron U.S.A. Inc. ("Chevron") with approximately 0.7 Bcf/d of LNG regasification capacity at the Sabine Pass LNG terminal. In December 2005, Chevron exercised its option to increase its reserved capacity by approximately 0.3 Bcf/d to approximately 1.0 Bcf/d, making advance capacity reservation fee payments to Sabine Pass LNG totaling $20.0 million. The advance capacity reservation fee payments are being amortized as a reduction of Chevron’s regasification capacity reservation fee under its TUA over a 10-year period beginning with the commencement of its TUA on July 1, 2009. As a result, we recorded the advance capacity reservation fee payments that Sabine Pass LNG received, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

As of December 31, 2011, we had recorded $4.0 million and $25.5 million as current and non-current deferred revenue on our Consolidated Balance Sheets, respectively, related to the Total and Chevron advance capacity reservation fees. As of December 31, 2010, we had recorded $4.0 million and $29.5 million as current and non-current deferred revenue on our Consolidated Balance Sheets, respectively, related to the Total and Chevron advance capacity reservation fees.

TUA Payments

Total and Chevron are obligated to make monthly TUA payments to Sabine Pass LNG in advance of the month of service. These monthly payments are recorded to current deferred revenue in the period cash is received and are then recorded as revenue in the next month when the TUA service is performed. As of December 31, 2011 and 2010, we had recorded $21.1 million and $21.0 million, respectively, as current deferred revenue on our Consolidated Balance Sheets related to Total's and Chevron's monthly TUA payments.

NOTE 15—DEBT AND DEBT—RELATED PARTIES

As of December 31, 2011 and 2010, our debt consisted of the following (in thousands):



	December 31,
	2011			2010
Current debt
2007 Term Loan	$	298,000		$	—
Convertible Senior Unsecured Notes	204,630			—
Total current debt	502,630			—
Current debt discount
Convertible Senior Unsecured Notes	(9,906		)	—
Total current debt, net of discount	$	492,724		$	—

Long-term debt (including related parties)
Senior Notes	$	2,215,500		$	2,215,500
2007 Term Loan	—			298,000
2008 Loans (including related parties)	282,293			262,657
Convertible Senior Unsecured Notes	—			204,630
Total long-term debt	2,497,793			2,980,787
Long-term debt discount
Senior Notes	(23,082		)	(27,777		)
Convertible Senior Unsecured Notes	—			(25,501		)
Total debt discount	(23,082		)	(53,278		)
Total long-term debt (including related parties), net of discount	$	2,474,711		$	2,927,509

Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2011 (in thousands):



	Payments Due for the Years Ended December 31,
	Total		2012		2013 to 2014		2015 to 2016		Thereafter
Debt (including related parties):
Senior Notes	$	2,215,500	$	—	$	550,000	$	1,665,500	$	—
2007 Term Loan	298,000		298,000		—		—		—
2008 Loans	282,293		—		—		—		282,293
Convertible Senior Unsecured Notes	204,630		204,630		—		—		—
Debt (including related parties)	$	3,000,423	$	502,630	$	550,000	$	1,665,500	$	282,293

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

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 Development, L.P. ("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. As of December 31, 2010, $298.0 million was outstanding under the 2007 Term Loan and included in long-term debt on our Consolidated Balance Sheets. During the second quarter of 2011, we reclassified $298.0 million of debt from a long-term liability to a current liability because our 2007 Term Loan was due within 12 months as of May 31, 2011.

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. 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 December 31, 2011, no holders had elected to convert their notes at the conversion rate.

During the second quarter of 2009, we reduced debt by exchanging $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes for a combination of $30.0 million cash and cash equivalents and 4.0 million shares of common stock, reducing our principal amount due in 2012 to $204.6 million. The remaining principal amount of the Convertible Senior Unsecured Notes are convertible into 5.8 million shares of our common stock.

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 December 31, 2011, the unamortized debt discount to the Convertible Senior Unsecured Notes was $9.9 million.

Senior Notes

In November 2006, Sabine Pass LNG issued an aggregate principal amount of $2,032.0 million of Senior Notes (the "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"). 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. 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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

•1.0% of the principal amount of the Senior Notes; or

•

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 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. During the years ended December 31, 2011 and 2010, Sabine Pass LNG made distributions of $313.6 million and $374.8 million, respectively, after satisfying all the applicable conditions in the Sabine Pass Indenture.

2008 Loans

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

NOTE 16—FINANCIAL INSTRUMENTS

We have entered into certain derivative instruments to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory ("LNG Inventory Derivatives"), and to hedge the price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal ("Fuel Derivatives"). Changes in the fair value of our derivatives instruments are reported in earnings because we have not elected to designate these derivative instruments as a hedging instrument that is required to qualify for cash flow hedge accounting. 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 derivative instruments are based on inputs that are quoted prices in active markets for similar assets or liabilities, resulting in Level 2 categorization of such measurements. The following table sets forth, by level within the fair value hierarchy, the fair value of our derivative instruments assets and liabilities at December 31, 2011 (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
LNG Inventory Derivatives asset (1)	$	—	$	1,951	$	—	$	1,951
Fuel Derivatives liability (2)	—		1,415		—		1,415

(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.

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):



	December 31, 2011				December 31, 2010
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2013 Notes (1)	$	550,000	$	555,500	$	550,000	$	541,750
2016 Notes, net of discount (1)	1,642,418		1,650,630		1,637,723		1,523,082
Convertible Senior Unsecured Notes, net of discount (2)	194,724		186,740		179,129		131,660
2007 Term Loan (3)	298,000		292,728		298,000		297,464
2008 Loans (4)	282,293		282,293		262,657		262,657


(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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(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.

NOTE 17—INCOME TAXES

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



	Year Ended December 31,
	2011			2010		2009
Current:
Federal	$	—		$	—	$	—
State	—			—		—
Foreign	277			—		—
Total current	277			—		—

Deferred:
Federal	$	—		$	—	$	—
State	—			—		—
Foreign	(117		)	—		—
Total deferred	(117		)	—		—

Total income tax provision (benefit)	$	160		$	—	$	—

The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:



	Year Ended December 31,
	2011		2010 ⁽¹⁾		2009 ⁽¹⁾
U.S. statutory tax rate	(35.0	)%	(35.0	)%	(35.0	)%
State tax benefit (net of federal benefits)	(6.2	)%	(9.2	)%	(7.1	)%
Foreign income tax provision	—	%	—	%	—	%
Deferred tax asset valuation reserve	42.1	%	26.0	%	42.6	%
Loss on early extinguishment of debt	—	%	17.8	%	—	%
Other	(0.9	)%	0.4	%	(0.5	)%
Effective tax rate as reported	—	%	—	%	—	%

(1) We have made certain changes in the classification and presentation of certain items. These changes do not affect the

disclosed effective tax rate.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Significant components of our deferred tax assets and liabilities at December 31, 2011 and 2010 are as follows (in thousands):



	Year Ended December 31,
	2011			2010
Deferred tax assets				(As Adjusted (1))
Net operating loss carryforwards ⁽²⁾
Federal	$	365,811		$	276,415
State	49,847			37,485
Capital gains	81,388			81,388
Share-based compensation expense	4,165			6,918
United Kingdom deferred tax assets	117			—
Other	19,565			7,290
Total deferred tax assets	$	520,893		$	409,496

Deferred tax liabilities
Investment in limited partnership	$	(79,281	)	$	(43,425	)
Other	(4,856		)	(12,952		)
Total deferred tax liabilities	$	(84,137	)	$	(56,377	)

Net deferred tax assets	$	436,756		$	353,119
Less: net deferred tax asset valuation allowance ⁽³⁾	(436,639		)	(353,119		)
	$	117		$	—


(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.

(3) A valuation allowance equal to our U.S. and state net deferred tax asset balance has been established due to the uncertainty of realizing the tax benefits related to our U.S. and state net deferred tax assets. The change in the U.S. and state deferred tax asset valuation allowance is $83.5 million and $33.4 million for the years ended December 31, 2011 and 2010, respectively.

Changes in the balance of unrecognized tax benefits are as follows (in thousands):



Balance as January 1, 2011	$	20,969
Additions based on tax positions related to current year	115,073
Additions for tax positions of prior years	—
Reductions for tax positions of prior years	(693		)
Settlements	—
Balance at December 31, 2011	$	135,349

At December 31, 2011, the amount of unrecognized tax benefits related to our federal NOL carryforward associated with uncertain tax positions was $135.3 million. Our effective tax rate would not be affected if the unrecognized federal tax benefits provided above were recognized. Currently, we do not recognize any accrued liabilities, interest and penalties associated with the unrecognized tax benefits provided above in our Consolidated Statements of Operations or our Consolidated Balance Sheets. We record interest and penalties related to unrecognized tax benefits to our income tax provision.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

During the third quarter of 2010, largely due to the increased level of trading activity in our shares, we experienced an ownership change within the provisions of Internal Revenue Code Section 382 (“Section 382”) that will subject approximately $855 million of our existing federal NOL carryforwards to an annual NOL utilization limitation. The applicable Section 382 limitation may affect our ability to fully utilize approximately $855 million of our existing federal NOL carryforward. Our ability to fully utilize our existing federal NOL carryforward is dependent on the amount of any net unrealized built in gains on the ownership change date and increasing the recognition of built-in gains in the five-year period following the above-referenced ownership change. We will continue to monitor trading activity in our shares which may cause an additional ownership change which may ultimately affect our ability to fully utilize our existing federal NOL carryforward.

We currently file tax returns in the U.S. federal jurisdiction, the United Kingdom and various state and local jurisdictions. We are no longer subject to U.S. federal, state or local income tax examinations by tax authorities for tax years prior to 2008. The Louisiana Department of Revenue is currently examining our 2007 through 2009 income tax returns.

In 2011, we generated a federal NOL of $595.4 million which is expected to be carried forward and applied against regular taxable income in future periods. Accounting for share-based compensation provides that when settlement of a share-based award contributes to an NOL carryforward, neither of the associated excess tax benefits nor the credit to additional paid-in-capital ("APIC") should be recorded until the share-based award deduction reduces income tax payable. Upon utilization of the loss in future periods, a benefit of $21.2 million will be reflected in APIC.

NOTE 18—SHARE-BASED COMPENSATION

We have granted options to purchase common stock to employees, consultants and outside directors under the Cheniere Energy, Inc. Amended and Restated 1997 Stock Option Plan ("1997 Plan") and the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan ("2003 Plan"). 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 years ended December 31, 2011, 2010 and 2009, the total share-based compensation expense recognized in our net loss (net of capitalization) was $26.4 million, $17.9 million and $19.2 million, respectively. The effect of a change in estimated forfeitures is recognized through a cumulative adjustment included in share-based compensation cost in the period of change in estimate. We consider many factors when estimating expected forfeitures, including types of awards, employee class and historical experience. For the years ended December 31, 2011, 2010 and 2009, the cumulative adjustment recognized in our compensation expense was $0.6 million, $1.1 million and $1.0 million, respectively. For the years ended December 31, 2011, 2010 and 2009, the total share-based compensation cost capitalized as part of the cost of capital assets was zero, zero and $1.1 million respectively.

The total unrecognized compensation cost at December 31, 2011 relating to non-vested share-based compensation arrangements granted under the 1997 Plan and 2003 Plan was $7.7 million. That cost is expected to be recognized over 4.0 years, with a weighted average period of 1.1 years.

We have disclosed the deferred tax benefit realized from share-based compensation exercised during the annual period in Note 17—"Income Taxes". A valuation allowance equal to the deferred tax asset has been established due to the uncertainty of realizing the tax benefits related to this deferred tax asset.

We received no proceeds from the exercise of stock options in the years ended December 31, 2011, 2010 and 2009.

Phantom Stock

On February 25, 2009, the Compensation Committee of our Board of Directors (the "Compensation Committee") made phantom stock grants of 5,545,000 shares pursuant to our 2003 Plan to all Cheniere executives, designated employees and one consultant. On June 12, 2009, the Compensation Committee made additional phantom stock grants of 800,000 shares to our Chief Executive Officer pursuant to the approval from our stockholders to increase the maximum number of shares granted to any one individual under our 2003 Plan during a calendar year from 1.0 million shares to 3.0 million shares. The shares were awarded under a time based plan and a performance based plan. The time based plan included an aggregate of 1,565,000 shares of phantom stock and provided for a three-year graded vesting schedule. The shares awarded under the time based plan vested equally on each

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

of December 15, 2009, 2010 and 2011. The performance based plan included an aggregate of 4,780,000 shares of phantom stock with each grant divided into three equal parts providing incentive compensation based on separate vesting terms. Vested shares of phantom stock were settled in cash or in shares of common stock, as determined by the Compensation Committee. In June 2009, we obtained approval from our stockholders to increase the number of shares of common stock available for issuance under our 2003 Plan from 11.0 million common shares to 21.0 million shares of common stock, which provided the requisite shares of common stock needed to satisfy vested phantom stock. We transferred the fair valued compensation liability associated with these phantom stock grants into additional paid-in capital. Using a Monte Carlo simulation, fair values were calculated as of June 12, 2009 for the time and performance based plans. For the year ended December 31, 2011, a total of $12.2 million was recognized as compensation expense relating to the vesting of time and performance based phantom stock grants. There was no unrecognized compensation cost at December 31, 2011 relating to non-vested phantom stock.

In May 2007, the Compensation Committee established the 2007 Incentive Compensation Plan ("2007 Bonus Plan") and the 2008-2010 Incentive Compensation Plan ("2008-2010 Bonus Plan"), each pursuant to the 2003 Plan, covering executive officers and other key employees for the performance periods of 2007 through 2010. A total of 537,000 and 1,794,000 shares of phantom stock were granted under the 2007 Bonus Plan and 2008-2010 Bonus Plan, respectively, payable in shares of common stock upon achievement of stock price hurdles established by the plans. In January 2008, 537,000 of shares of common stock were issued as the stock price hurdle for the 2007 Bonus Plan was achieved. During the fourth quarter of 2008, certain executives and key employees forfeited 1,041,000 shares of their phantom shares granted under the 2008-2010 Bonus Plan with no concurrent consideration. In connection with the forfeitures of the phantom shares, a total of $5.1 million of unrecognized compensation cost was recognized. Subsequently, on February 19, 2009, the Compensation Committee canceled the 2008–2010 Plan.

Stock Options

We estimate the fair value of stock options at the date of grant using a Black-Scholes valuation model. The risk-free rate is based on the U.S. Treasury securities yield curve in effect at the time of grant. The expected term (estimated period of time outstanding) of stock options granted is based on the “simplified” method of estimating the expected term for “plain vanilla” stock options, and varies based on the vesting period and contractual term of the stock option. Expected volatility for stock options granted is based on an equally weighted average of the implied volatility of exchange traded stock options on our common stock expiring more than one year from the measurement date, and historical volatility of our common stock for a period equal to the stock option’s expected life. We have not declared dividends on our common stock. We did not issue any options to purchase shares of our common stock during the year ended December 31, 2011.

The table below provides a summary of option activity under the 1997 Plan and 2003 Plan as of December 31, 2011:



	Options		Weighted Average Exercise Price			Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
	(in thousands)						(in thousands)
Outstanding at January 1, 2011	783		$	26.44
Granted	—		—
Exercised	—		—
Forfeited or Expired	(12	)	25.96
Outstanding at December 31, 2011	771		$	26.45	—	3.08	$	—
Exercisable at December 31, 2011	771		$	26.45		3.08	$	—

The weighted average grant-date fair value of options granted during the years ended December 31, 2011, 2010 and 2009 was zero. The total intrinsic value of options exercised during the years ended December 31, 2011, 2010 and 2009 was zero.

Stock and Non-Vested Stock

We have granted stock, phantom stock and restricted stock and non-vested restricted stock to employees, executive officers, outside directors and consultants under the 2003 Plan. Grants of non-vested stock are accounted for on an intrinsic value basis. The amortization of the calculated value of non-vested stock grants is accounted for as a charge to compensation and an increase in additional paid-in-capital over the requisite service period.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

For the years ended December 31, 2011, 2010 and 2009, we issued 5,262,000 shares, 502,000 shares and 522,000 shares, respectively, of phantom stock awards to our executives and certain officers.

For the years ended December 31, 2011, 2010 and 2009, we issued 2,565,000 shares, 1,234,000 shares and 325,000 shares, respectively, of restricted stock awards to our employees, executives, directors and a consultant as performance, retention, service and new hire awards. A majority of the awards were issued with a one, three or four-year graded vesting period. A certain group of 2007 retention grants received a vesting schedule of 50% on December 1, 2008, 30% on December 1, 2009 and 20% on June 1, 2010. A certain group of 2011 restricted stock awards received a vesting schedule of 33% on June 30, 2011, 33% on June 30, 2012, and 33% on June 30, 2013.

On May 25, 2007, the Compensation Committee approved a bonus plan covering substantially all employees not otherwise included in the 2007 Plan. This plan provided covered employees the ability to earn bonuses based on the achievement of established annual performance goals as well as a stock price appreciation goal. The fair value of the grants was recalculated at each balance sheet date until the total number of restricted shares was granted in January 2008. Because of the existence of the stock price appreciation goal, which was a market condition, the restricted stock was not eligible for amortization under the straight-line method, and each vesting tranche is being amortized separately.

The table below provides a summary of the status of our non-vested shares under the 2003 Plan as of December 31, 2011 (in thousands except for per share information):



	Non-Vested Shares		Weighted Average Grant Date Fair Value Per Share
Non-vested at January 1, 2011	927		$	4.30
Granted	2,557		7.72
Vested	(1,566	)	7.26
Forfeited	(39	)	6.83
Non-vested at December 31, 2011	1,879		$	7.75

The weighted average grant date fair values per share of restricted stock granted during the years ended December 31, 2011, 2010 and 2009 were $7.72, $3.31, and zero, respectively. The total grant date fair value per share of shares vested during the years ended December 31, 2011, 2010 and 2009 were $7.26, $5.54 and $3.07, respectively.

Share-based Plan Descriptions and Information

Our 1997 Plan provides for the issuance of stock options to purchase up to 5.0 million shares of our common stock, all of which have been granted. Non-qualified stock options were granted to employees, contract service providers and outside directors.

In June 2009, we obtained approval from our stockholders to increase the number of shares of common stock available for issuance under our 2003 Plan from 11.0 million shares to 21.0 million shares. These awards may be in the form of non-qualified stock options, incentive stock options, purchased stock, restricted (non-vested) stock, bonus (unrestricted) stock, stock appreciation rights, phantom stock and other share-based performance awards deemed by the Compensation Committee to be consistent with the purposes of the 2003 Plan. To date, the only awards made by the Compensation Committee have been in the form of non-qualified stock options, restricted stock, restricted stock units and phantom shares.

401(k) Plan

In 2005, we established a defined contribution pension plan ("401(k) Plan"). The 401(k) Plan allows eligible employees to contribute up to 100% of their compensation up to the IRS maximum. We match each employee’s salary deferrals (contributions) up to six percent of compensation and may make additional contributions at our discretion. Effective January 1, 2007, employees are immediately vested in the contributions made by us. Our contributions to the 401(k) Plan were $1.1 million, $1.0 million and $1.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. We have made no discretionary contributions to the 401(k) Plan to date.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

NOTE 19—COMPREHENSIVE LOSS

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



	Year Ended December 31,
	2011			2010			2009
Net loss	$	(198,756	)	$	(76,203	)	$	(161,490	)
Other comprehensive (loss) income item:
Foreign currency translation	(85		)	(40		)	21
Comprehensive loss	$	(198,841	)	$	(76,243	)	$	(161,469	)

NOTE 20—COMMITMENTS AND CONTINGENCIES

LNG Terminal Commitments and Contingencies

Obligations under LNG TUAs

Sabine Pass LNG has entered into third-party TUAs with Total and Chevron to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG terminal.

Obligations under Bechtel EPC Contract

In November 2011, Sabine Pass Liquefaction entered into a lump sum turnkey agreement with Bechtel for the engineering, procurement and construction of the first two LNG trains and related facilities at the Sabine Pass LNG terminal (the "EPC Contract"), with each LNG train having a nominal capacity of approximately 4.5 mtpa. The contract provides that Sabine Pass Liquefaction will pay Bechtel a contract price of $3.9 billion, which is subject to adjustment by change order. Sabine Pass Liquefaction has the right to terminate the EPC Contract for its convenience, in which case Bechtel will be paid (i) the portion of the contract price for the work performed, (ii) costs reasonably incurred by Bechtel on account of such termination and demobilization, and (iii) 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.

Crest Royalty

Under a settlement agreement dated as of June 14, 2001, we agreed to pay or cause certain affiliates, successors and assigns to pay a royalty, which we refer to as the Crest Royalty. This Crest Royalty is calculated based on the volume of natural gas processed through covered LNG facilities. In 2003, Freeport LNG contractually assumed the obligation to pay the Crest Royalty for natural gas processed at Freeport LNG’s receiving terminal. The Crest Royalty is subject to a maximum of approximately $11.0 million and a minimum of $2.0 million per production year. The calculation of the Crest Royalty, and the scope of Freeport LNG's assumed obligation to pay the Crest Royalty, are being litigated in a breach of contract and declaratory judgment action pending in Texas state court.

Restricted Net Assets

At December 31, 2011, our restricted net assets of consolidated subsidiaries were approximately ($240.2) million.

Other Commitments

In the ordinary course of business, we have issued surety bonds related to our offshore oil and gas operations and entered into certain multi-year licensing and service agreements, none of which are considered material to our financial position.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

Legal Proceedings

NOTE 21—BUSINESS SEGMENT INFORMATION

We have three operating business segments: LNG 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 terminal business segment consists of the operational Sabine Pass LNG terminal, approximately 88.8% owned (at December 31, 2011) in western Cameron Parish, Louisiana on the Sabine Pass Channel and two other LNG 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 terminal to numerous interconnections 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 enter into long-term commercial agreements for regasification capacity; develop a portfolio of long-term, short-term, and spot LNG purchase and sale agreements; assist Cheniere Partners in negotiations with potential customers for importing and exporting natural gas through the Sabine Pass LNG terminal; and enter into business relationships for the domestic marketing of natural gas imported by Cheniere Marketing as LNG to the Sabine Pass LNG terminal.

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



	Segments
	LNG Terminal			Natural Gas Pipeline			LNG & Natural Gas Marketing			Corporate and Other (1)			Total Consolidation
As of or for the Year Ended December 31, 2011
Revenues	$	274,272		$	50		$	13,554		$	2,568		$	290,444
Intersegment revenues (losses) (2) (3)	14,607			48			(13,731		)	(924		)	—
Depreciation, depletion and amortization	43,421			16,641			1,105			2,238			63,405
Non-cash compensation	2,096			550			9,258			14,460			26,364
Income (loss) from operations	143,615			(24,278		)	(28,380		)	(32,811		)	58,146
Interest expense, net	(173,590		)	(45,733		)	—			(40,070		)	(259,393		)
Goodwill	76,819			—			—			—			76,819
Total assets	1,875,613			537,671			67,792			434,249			2,915,325
Expenditures for additions to long-lived assets	9,617			258			16			732			$	10,623

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued



	Segments
	LNG Terminal		Natural Gas Pipeline		LNG & Natural Gas Marketing		Corporate and Other (1)		Total Consolidation
As of or for the Year Ended December 31, 2010
Revenues	269,538		95		19,022		2,858		291,513
Intersegment revenues (losses) (4) (5) (6) (7)	130,954		255		(129,137	)	(2,072	)	—
Depreciation, depletion and amortization	42,683		15,063		1,087		4,418		63,251
Non-cash compensation	1,764		553		5,791		9,770		17,878
Income (loss) from operations	273,810		(22,014	)	(131,891	)	(15,282	)	104,623
Interest expense, net	(199,405	)	(45,228	)	—		(17,413	)	(262,046	)
Goodwill	76,819		—		—		—		76,819
Total assets	1,899,130		554,049		96,781		3,548		2,553,508
Expenditures for additions to long-lived assets	4,528		55		(349	)	1,543		5,777

As of or for the Year Ended December 31, 2009
Revenues	170,071		102		8,087		2,866		181,126
Intersegment revenues (losses) (4) (5) (6) (7)	252,928		932		(249,196	)	(4,664	)	—
Depreciation, depletion and amortization	33,203		14,731		1,505		4,790		54,229
Non-cash compensation	1,300		583		5,661		11,652		19,196
Loss from operations	333,710		(21,453	)	(260,514	)	(28,247	)	23,496
Interest expense, net	(157,057	)	(44,912	)	—		(41,326	)	(243,295	)
Goodwill	76,819		—		—		—		76,819
Total assets	2,013,618		569,626		147,164		2,214		2,732,622
Expenditures for additions to long-lived assets	106,628		(4,376	)	1,081		(539	)	102,794


(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.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—Continued

(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.

NOTE 22—SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS

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



	Year Ended December 31,
	2011		2010		2009
Cash paid during the year for interest, net of amounts capitalized	$	190,849	$	263,520	$	90,702

NOTE 23—SUBSEQUENT EVENTS (UNAUDITED)

In January 2012, we repaid in full the outstanding principal balance of the $298.0 million 2007 Term Loan due May 31, 2012. We used a portion of the net proceeds from the public offering of 41,745,000 shares of common stock in December 2011 to repay the 2007 Term Loan. The aggregate repayment amount was $298.2 million, including the outstanding principal amount and accrued interest through January 5, 2012.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

SUMMARIZED QUARTERLY FINANCIAL DATA

(unaudited)

Quarterly Financial Data—(in thousands, except per share amounts)



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2011:
Revenues	$	79,231		$	72,810		$	65,813		$	72,590
Income from operations	23,566			16,461			10,355			7,764
Loss before non-controlling interest	(40,479		)	(48,456		)	(55,469		)	(58,934		)
Net loss	(39,838		)	(47,171		)	(53,936		)	(57,811		)
Net loss per share—basic and diluted	(0.60		)	(0.67		)	(0.67		)	(0.66		)

Year ended December 31, 2010:
Revenues	$	79,517		$	68,275		$	68,248		$	75,473
Income from operations	31,046			24,690			22,383			26,504
Income (loss) before non-controlling interest	(35,649		)	85,172			(41,301		)	(86,616		)
Net income (loss)	(35,167		)	85,677			(40,580		)	(86,133		)
Net income (loss) per share—basic	(0.64		)	1.55			(0.73		)	(1.51		)
Net income (loss) per share—diluted	(0.64		)	0.86			(0.73		)	(1.51		)

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL

DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on their evaluation as of the end of the fiscal year ended December 31, 2011, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (i) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (ii) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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.

Management’s Report on Internal Control Over Financial Reporting

Our Management's Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements on page 54 and is incorporated herein by reference.

ITEM 9B. OTHER INFORMATION

None.

PART III

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Items 10 through 14 of Part III of this Report is incorporated by reference from Cheniere’s definitive proxy statement, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2011.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES


(a)	Financial Statements, Schedules and Exhibits


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



Management’s Reports to the Stockholders of Cheniere Energy, Inc.	54
Reports of Independent Registered Public Accounting Firm—Ernst & Young LLP	55
Consolidated Balance Sheets	57
Consolidated Statements of Operations	58
Consolidated Statements of Stockholders’ (Deficit) Equity	59
Consolidated Statements of Cash Flows	60
Notes to Consolidated Financial Statements	61
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data	87


(2)	Financial Statement Schedules:



Schedule I—Condensed Financial Information of Registrant for the years ended December 31, 2011, 2010 and 2009	98

(3) Exhibits:



Exhibit No.		Description
2.1*		Settlement and Purchase Agreement, dated and effective as of June 14, 2001 by and between the Company, CXY Corporation, Crest Energy, L.L.C., Crest Investment Company and Freeport LNG Terminal, LLC, and two related letter agreements each dated February 27, 2003. (Incorporated by reference to Exhibit 10.36 to Cheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on January 25, 2007)

2.2*		Agreement and Plan of Merger, dated February 8, 2005, by and among Cheniere LNG, Inc., Cheniere Acquisition, LLC, BPU Associates, LLC and BPU LNG, Inc. (Incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on February 8, 2005)

3.1*		Restated Certificate of Incorporation of the Company. (Incorporated by reference to Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2004 (SEC File No. 001-16383), filed on August 10, 2004)

3.2*		Certificate of Amendment of Restated Certificate of Incorporation of the Company. (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on February 8, 2005)

3.3*		Certificate of Amendment of Restated Certificate of Incorporation of the Company. (Incorporated by reference to Exhibit 4.3 to the Company's Registration Statement on Form S-8 (SEC File No. 333-160017), filed on June 16, 2009)

3.4*		Amended and Restated By-laws of the Company. (Incorporated by reference to Exhibit 4.3 to the Company's Registration Statement on Form S-8 (SEC File No. 333-112379), filed on January 30, 2004)

3.5*		Amendment No. 1 to Amended and Restated By-laws of the Company. (Incorporated by reference to Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 6, 2005)

3.6*		Amendment No. 2, dated September 6, 2007, to the Amended and Restated By-Laws of Cheniere Energy, Inc. (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on September 12, 2007)

4.1*		Specimen Common Stock Certificate of the Company. (Incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1 (SEC File No. 333-10905), filed on August 27, 1996)

4.2*		Certificate of Designation of Series A Junior Participating Preferred Stock. (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K (SEC File No. 001 16383), filed on October 14, 2004)

4.3*		Rights Agreement by and between the Company and U.S. Stock Transfer Corp., as Rights Agent, dated as of October 14, 2004. (Incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on October 14, 2004)

4.4*		First Amendment to Rights Agreement by and between the Company and U.S. Stock Transfer Corp., as Rights Agent, dated January 24, 2005. (Incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on January 24, 2005)

4.5*		Second Amendment to Rights Agreement by and between Cheniere Energy, Inc. and Computershare Trust Company, N.A. (formerly U.S. Stock Transfer Corp.), as Rights Agent, dated as of October 24, 2008 (filed herewith). (Incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on October 24, 2008)

4.6*		Certificate of Designations of Series B Preferred Stock of Cheniere Energy, Inc. (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on August 18, 2008)



4.7*		Amended and Restated Certificate of Designations of Series B Preferred Stock of Cheniere Energy, Inc. (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on December 23, 2010)

4.8*		Form of Series B Preferred Stock Certificate of Cheniere Energy, Inc. (Incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on August 18, 2008)

4.9*		Indenture, dated as of July 27, 2005, between the Company, as issuer, and The Bank of New York, as trustee. (Incorporated by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on July 27, 2005)

4.10*		Indenture, dated as of November 9, 2006, between Sabine Pass LNG, L.P., as issuer, and The Bank of New York, as trustee. (Incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)

4.11*		Form of 7.25% Senior Secured Note due 2013 (Included as Exhibit A1 to Exhibit 4.9 above)

4.12*		Form of 7.50% Senior Secured Note due 2016 (Included as Exhibit A1 to Exhibit 4.9 above)

10.1*		LNG Terminal Use Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)

10.2*		Amendment of LNG Terminal Use Agreement, dated January 24, 2005, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 10, 2005)

10.3*		Amendment to LNG Terminal Use Agreement, dated June 15, 2010, by and between Total Gas & Power North America, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 6, 2010)

10.4*		Omnibus Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)

10.5*		Guaranty, dated as of November 9, 2004, by Total S.A. in favor of Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001 16383), filed on November 15, 2004)

10.6*		LNG Terminal Use Agreement, dated November 8, 2004, between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)

10.7*		Amendment to LNG Terminal Use Agreement, dated December 1, 2005, by and between Chevron U.S.A., Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.28 to Sabine Pass LNG, L.P.'s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on November 22, 2006)

10.8*		Amendment of LNG Terminal Use Agreement, dated June 16, 2010, by and between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 6, 2010)

10.9*		Omnibus Agreement, dated November 8, 2004, between Chevron U.S.A., Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)

10.10*		Guaranty Agreement, dated as of December 15, 2004, from ChevronTexaco Corporation to Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.12 to Sabine Pass LNG, L.P.'s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on November 22, 2006)

10.11*		Amended and Restated Terminal Use Agreement, dated November 9, 2006, by and between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)

10.12*		Guarantee Agreement, dated as of November 9, 2006, by the Company. (Incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)



10.13*		Amendment of LNG Terminal Use Agreement, dated June 25, 2007, by and between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 26, 2007)

10.14*		Cooperative Endeavor Agreement & Payment in Lieu of Tax Agreement, dated October 23, 2007 (amending the Amended and Restated Terminal Use Agreement, dated November 9, 2006, by and between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P.). (Incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2007)

10.15*		Assignment and Assumption Agreement, dated June 24, 2010, by and between Cheniere Marketing, LLC and Cheniere Energy Investments, LLC (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 28, 2010)

10.16*		Guarantee Agreement, dated June 24, 2010, by Cheniere Energy, Inc. in favor of Cheniere Energy Investments, LLC (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 28, 2010)

10.17*		LNG Sale and Purchase Agreement (FOB), dated October 25, 2011, between Sabine Pass Liquefaction, LLC (Seller) and BG Gulf Coast LNG, LLC (Buyer). (Incorporated by reference to Exhibit 10.1 to Cheniere Partners' Current Report on Form 8-K (SEC File No. 001-33366), filed on October 26, 2011)

10.18*		Amended and Restated LNG Sale and Purchase Agreement (FOB), dated January 25, 2012, between Sabine Pass Liquefaction, LLC (Seller) and BG Gulf Coast LNG, LLC (Buyer). (Incorporated by reference to Exhibit 10.1 to Cheniere Partners' Current Report on Form 8-K (SEC File No. 001-33366), filed on January 26, 2012)

10.19*		Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated November 11, 2011, between Sabine Pass Liquefaction, LLC (Owner) and Bechtel Oil, Gas and Chemicals, Inc. (Contractor). (Incorporated by reference to Exhibit 10.1 to Cheniere Partners' Current Report on Form 8-K (SEC File No. 001-33366), filed on November 14, 2011)

10.20*		LNG Sale and Purchase Agreement (FOB), dated November 21, 2011, between Sabine Pass Liquefaction, LLC (Seller) and Gas Natural Aprovisionamientos SDG S.A. (Buyer). (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-33366), filed on November 21, 2011)

10.21*		LNG Sale and Purchase Agreement (FOB), dated December 11, 2011, between Sabine Pass Liquefaction, LLC (Seller) and GAIL (India) Limited (Buyer). (Incorporated by reference to Exhibit 10.1 to Cheniere Partners' Current Report on Form 8-K (SEC File No. 001-33366), filed on December 12, 2011)

10.22*		LNG Sale and Purchase Agreement (FOB), dated January 30, 2012, between Sabine Pass Liquefaction, LLC (Seller) and Korea Gas Corporation (Buyer). (Incorporated by reference to Exhibit 10.1 to Cheniere Partners' Current Report on Form 8-K (SEC File No. 1-33366), filed on January 30, 2012)

10.23*		LNG Lease Agreement, dated June 24, 2008, between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 11, 2008)

10.24*		LNG Lease Agreement, dated September 30, 2011, by and between Cheniere Marketing, LLC and Cheniere Energy Investments, LLC. (Incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 11, 2011)

10.25*		Surrender of Capacity Rights Agreement, dated March 26, 2010, by and between Cheniere Marketing, LLC and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on March 31, 2010)

10.26*		Amended and Restated Capacity Rights Agreement, dated June 24, 2010, by and between Sabine Pass LNG, L.P. and JPMorgan LNG Co. (Incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 28, 2010)

10.27*		Amendment No. 1 to Amended and Restated Capacity Rights Agreement, dated December 16, 2010, by and between Sabine Pass LNG, L.P. and JPMorgan LNG Co. . (Incorporated by reference to Exhibit 10.20 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 3, 2011)

10.28*		Amendment No. 2 to Amended and Restated Capacity Rights Agreement, dated April 1, 2011, by and between Sabine Pass LNG, L.P. and JPMorgan LNG Co. (Incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 6, 2011)



10.29*		Tri-Party Agreement, dated June 24, 2010, by and among Cheniere Energy Investments, LLC, Sabine Pass LNG, L.P. and JPMorgan LNG Co, (Incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 28, 2010)

10.30*		Amendment No. 1 to Tri-Party Agreement, dated December 16, 2010, by and among Cheniere Energy Investments, LLC, Sabine Pass LNG, L.P. and JPMorgan LNG Co. (Incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 3, 2011)

10.31*		Amended LNG Services Agreement, dated June 24, 2010, by and between Cheniere Marketing, LLC and JPMorgan LNG Co. (Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 28, 2010)

10.32*		Amendment No. 2 to LNG Services Agreement, dated December 16, 2010, by and between Cheniere Marketing, LLC and JPMorgan LNG Co. (Incorporated by reference to Exhibit 10.27 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 3, 2011)

10.33*		Amendment No. 3 to LNG Services Agreement, dated February 15, 2011, by and between Cheniere Marketing, LLC and JPMorgan LNG Co. (Incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed May 6, 2011.

10.34*		Amendment No. 4 to LNG Services Agreement, dated April 1, 2011, by and between Cheniere Marketing, LLC and JPMorgan LNG Co. (Incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 6, 2011.

10.35*		Variable Capacity Rights Agreement, dated June 24, 2010, by and between Cheniere Marketing, LLC and Cheniere Energy Investments, LLC (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 28, 2010)

10.36*		Amended and Restated Services Agreement, dated June 24, 2010, by and between Cheniere Energy Partners, L.P. and Cheniere LNG Terminals, Inc. (Incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 28, 2010)

10.37*		Collateral Trust Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New York, as collateral trustee, Sabine Pass LNG-GP, Inc. and Sabine Pass LNG-LP, LLC. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)

10.38*		Amended and Restated Parity Lien Security Agreement, dated November 9, 2006, by and between Sabine Pass LNG, L.P. and The Bank of New York, as collateral trustee. (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)

10.39*		Third Amended and Restated Multiple Indebtedness Mortgage, Assignment of Rents and Leases and Security Agreement, dated November 9, 2006, between the Sabine Pass LNG, L.P. and The Bank of New York, as collateral trustee. (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)

10.40*		Amended and Restated Parity Lien Pledge Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., Sabine Pass LNG-GP, Inc., Sabine Pass LNG-LP, LLC and The Bank of New York, as collateral trustee. (Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)

10.41*		Security Deposit Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New York, as collateral trustee, and The Bank of New York, as depositary agent. (Incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)

10.42*		Credit Agreement dated August 15, 2008, by and among Cheniere Common Units Holding, LLC the other Loan Parties (as defined therein), The Bank of New York Mellon, as administrative agent and collateral agent and the Lenders (as defined therein). (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on August 18, 2008)

10.43*		First Amendment to Credit Agreement, dated September 15, 2008, among Cheniere Common Units Holding, LLC, the other Loan Parties (as defined therein), The Bank of New York Mellon, as administrative agent and collateral agent and the Lenders (as defined therein) (Incorporated by reference to Exhibit 10.63 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2009)



10.44*		Second Amendment to Credit Agreement, First Amendment to Guarantee and Collateral Agreement (Crest Entities) and First Amendment to Guarantee and Collateral Agreement (Non-Crest Entities), dated December 31, 2008, by Cheniere Common Units Holding, LLC, the loan parties, the guarantors and the grantors signatory thereto, the lenders signatory thereto and The Bank of New York Mellon, as administrative agent and as collateral agent (Incorporated by reference to Exhibit 10.64 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2009)

10.45*		Third Amendment to Credit Agreement and Third Amendment to Guarantee and Collateral Agreement (Non-Crest Entities), dated April 3, 2009, among Cheniere Common Units Holding, LLC, the loan parties, the guarantors and the grantors signatory thereto, the lenders signatory thereto and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2009)

10.46*		Fourth Amendment to Credit Agreement, dated April 9, 2009, among Cheniere Common Units Holding, LLC, the other Loan Parties (as defined therein), the Lenders (as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2009)

10.47*		Amendment No. Four-A to Credit Agreement, dated April 27, 2009, among Cheniere Common Units Holding, LLC, the other Loan Parties (as defined therein), the Lenders (as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2009)

10.48*		Amendment No. Four-B to Credit Agreement, dated April 28, 2009, among Cheniere Common Units Holding, LLC, the other Loan Parties (as defined therein), the Lenders (as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2009)

10.49*		Amendment No. Four-C to Credit Agreement, dated June 23, 2009, among Cheniere Common Units Holding, LLC, the other Loan Parties (as defined therein), the Lenders (as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 7, 2009)

10.50*		Amendment No. Four-D to Credit Agreement, dated June 29, 2009, among Cheniere Common Units Holding, LLC, the other Loan Parties (as defined therein), the Lenders (as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 7, 2009)

10.51*		Fifth Amendment to Credit Agreement, dated September 17, 2009, by Cheniere Common Units Holding, LLC, the Loan Parties (as defined therein), the Lenders (as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2009)

10.52*		Sixth Amendment to Credit Agreement, Second Amendment to Security Deposit Agreement and Consent, dated June 24, 2010, by and among Cheniere Common Units Holding, LLC, the Loan Parties (as defined therein), the Lenders (as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 28, 2010)

10.53*		Seventh Amendment to Credit Agreement, dated November 3, 2010, by and among Cheniere Common Units Holding, LLC, the Loan Parties (as defined therein), the Lenders (as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 5, 2010)

10.54*		Eighth Amendment to Credit Agreement and Second Amendment to Investors' Agreement, dated December 9, 2010, by and among Cheniere Common Units Holding, LLC, the Loan Parties (as defined therein), the Lenders (as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on December 10, 2010)

10.55*		Ninth Amendment to Credit Agreement, Fourth Amendment to Guarantee and Collateral Agreement (Crest Entities) and Fifth Amendment to Guarantee and Collateral Agreement (Non-Crest Entities), dated September 13, 2011, by and among Cheniere Common Units Holding, LLC, the Loan Parties, the Guarantors, the Grantors and the Lenders (each as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent (Incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 7, 2011)



10.56		Tenth Amendment to Credit Agreement, dated January 5, 2012, by Cheniere Common Units Holding, LLC, the Loan Parties (as defined therein), the Lenders (as defined therein) and The Bank of New York Mellon, as administrative agent and collateral agent.

10.57*		Guarantee and Collateral Agreement (Crest Entities), dated August 15, 2008, made by the entities party thereto in favor of The Bank of New York Mellon, as collateral agent. (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on August 18, 2008)

10.58*		Guarantee and Collateral Agreement (Non-Crest Entities), dated August 15, 2008, by Cheniere Common Units Holding, LLC and the other entities party thereto in favor of The Bank of New York Mellon, as collateral agent. (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on August 18, 2008)

10.59*		Waiver to Credit Agreement and Guarantee and Collateral Agreement (Non-Crest Entities), dated December 13, 2008, among Cheniere Common Units Holding, LLC, Cheniere Midstream Holdings, Inc., Cheniere LNG Services, Inc., GSO Special Situations Fund LP, GSO Credit Opportunities Fund (Helios), L.P., GSO Special Situations Overseas Master Fund Ltd., Blackstone Distressed Securities Fund L.P., Scorpion Capital Partners LP and The Bank of New York Mellon, as collateral agent and administrative agent (Incorporated by reference to Exhibit 10.67 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2009)

10.60*		Second Amendment to Guarantee and Collateral Agreements, dated December 31, 2008, by Cheniere Midstream Holdings, Inc., Sabine Pass Tug Services, LLC, Cheniere LNG, Inc., Cheniere LNG Terminals, Inc., Cheniere Marketing, LLC, the Lenders signatory thereto and The Bank of New York Mellon, as collateral agent (Incorporated by reference to Exhibit 10.68 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2009)

10.61*		Third Amendment to Guarantee and Collateral Agreement (Crest Entities) and Fourth Amendment to Guarantee and Collateral Agreement (Non-Crest Entities), dated September 17, 2009, by Cheniere Common Units Holding, LLC, the guarantors and the grantors signatory thereto and The Bank of New York Mellon, as collateral agent (Incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2009)

10.62*		Assumption Agreement, dated September 17, 2009, by Cheniere Marketing, LLC (formerly Cheniere Marketing, Inc.) in favor of The Bank of New York Mellon, as collateral agent (Incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2009)

10.63*		Security Deposit Agreement, dated August 15, 2008, by and among Cheniere LNG Holdings, LLC and The Bank of New York Mellon, as collateral agent and depositary agent. (Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on August 18, 2008)

10.64*		First Amendment to Security Deposit Agreement, dated June 19, 2009, by and between Cheniere LNG Holdings, LLC and The Bank of New York Mellon as collateral agent and depositary agent (Incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 7, 2009)

10.65*		Investors' Agreement, dated August 15, 2008, by and between Cheniere Energy, Inc., Cheniere Common Units Holding, LLC and the investors named therein. (Incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on August 18, 2008)

10.66*		First Amendment to Investors' Agreement, dated November 11, 2008, among Cheniere Energy, Inc., Cheniere Common Units Holding, LLC, GSO Special Situations Fund LP, GSO Origination Funding Partners LP, Blackstone Distressed Securities Fund L.P., GSO COF Facility LLC, and Scorpion Capital Partners LP (Incorporated by reference to Exhibit 10.71 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2009)

10.67*		Amended and Restated Investors' Agreement, dated September 13, 2011, by and among Cheniere Energy, Inc., Cheniere Common Units Holding, LLC, and Scorpion Capital Partners, LP. (Incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed November 7, 2011.

10.68*		Master Ex-Ship LNG Sales Agreement, dated April 26, 2007, between Cheniere Marketing, Inc. and Gaz de France International Trading S.A.S., including Letter Agreement, dated April 26, 2007, and Specific Order No. 1, dated April 26, 2007. (Incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2007)



10.69*		GDF Transatlantic Option Agreement, dated April 26, 2007, between Cheniere Marketing, Inc. and Gaz de France International Trading S.A.S. (Incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2007)

10.70*		Purchase and Sale Agreement, dated as of April 21, 2010, by and among Cheniere FLNG, L.P., Cheniere Energy, Inc. and Zachry American Infrastructure, LLC and Hastings Funds Management (USA), Inc. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on April 22, 2010)

10.71*†		Cheniere Energy, Inc. Amended and Restated 1997 Stock Option Plan. (Incorporated by reference to Exhibit 10.14 to the Company's Quarterly on Form 10-Q (SEC File No. 000-16383), filed on November 4, 2005)

10.72*†		Form of Amendment to Nonqualified Stock Option Agreement under the Cheniere Energy, Inc. Amended and Restated 1997 Stock Option Plan pursuant to the Nonqualified Stock Option Agreement. (Incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 7, 2008)

10.73*†		Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.14 to the Company's Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 4, 2005)

10.74*†		Addendum to Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2005 (SEC File No. 001-16383), filed on March 13, 2006)

10.75*†		Amendment No. 1 to Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 4.10 to the Company's Registration Statement on Form S-8 (SEC File No. 333-134886), filed on June 9, 2006)

10.76*†		Amendment No. 2 to Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.84 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2007)

10.77*†		Amendment No. 3 to Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit A to the Company's Proxy Statement (SEC File No. 001-16383), filed on April 23, 2008)

10.78*†		Amendment No. 4 to the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive plan (Incorporated by reference to Exhibit 10.2 to the Company' Current Report on Form 8-K (SEC File No. 001-16383), filed on June 15, 2009)

10.79*†		Form of Non-Qualified Stock Option Grant for Employees and Consultants (three-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.2 to the Company' Current Report on Form 8-K (SEC File No. 001-16383), filed on January 11, 2007)

10.80*†		Form of Non-Qualified Stock Option Grant for Employees and Consultants (four-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.3 to the Company' Current Report on Form 8-K (SEC File No. 001-16383), filed on January 11, 2007)

10.81*†		Form of Non-Qualified Stock Option Grant for Non-Employee Directors under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.4 to the Company' Current Report on Form 8-K (SEC File No. 001-16383), filed on January 11, 2007)

10.82*†		Form of Amendment to Non-Qualified Stock Option Grant under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.7 to the Company' Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 7, 2008)

10.83*†		Form of Restricted Stock Grant (three-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.5 to the Company' Current Report on Form 8-K (SEC File No. 001-16383), filed on January 11, 2007)

10.84*†		Form of Restricted Stock Grant (four-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.6 to the Company' Current Report on Form 8-K (SEC File No. 001-16383), filed on January 11, 2007)

10.85*†		Form of Restricted Stock Agreement for Non-Employee Directors. (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 1, 2007)



10.86*†		Form of Cancellation and Grant of Non-Qualified Stock Options (three-year vesting) under the Cheniere Energy, Inc. 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on August 2, 2005)

10.87*†		Form of Amendment to Non-Qualified Stock Option Agreement. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on April 3, 2007)

10.88*†		Form of French Stock Option Grant for Employees and Consultants (four-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.91 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2007)

10.89*†		Form of French Restricted Shares Grant for Employees, Consultants and Non-Employee Directors (three-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.92 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2007)

10.90*†		Form of French Restricted Shares Grant for Employees, Consultants and Non-Employee Directors (four-year vesting) under the Cheniere Energy, Inc. Amended and Restated 2003 Stock Incentive Plan (Incorporated by reference to Exhibit 10.93 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2007)

10.91*†		Indefinite Term Employment Agreement, dated February 20, 2006, between Cheniere International, Inc. and Jean Abiteboul; Letter Agreement, dated February 23, 2006, between Cheniere Energy, Inc. and Jean Abiteboul; Amendment to a Contract of Employment, dated March 20, 2007, between Cheniere LNG Services SARL and Jean Abiteboul; and Amendment to Indefinite Term Contract of Employment, dated January 18, 2008, between Cheniere LNG Services and Jean Abiteboul (Incorporated by reference to Exhibit 10.94 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on February 27, 2009)

10.92*†		Jean Abiteboul's secondment arrangement effective April 30, 2010. (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on April 27, 2010)

10.93†		Summary of Compensation for Executive Officers.

10.94†		Summary of Compensation to Non-Employee Directors.

10.95*†		Cheniere Energy, Inc. 2008 Short-Term Retention Plan. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on May 14, 2008)

10.96*†		Form of Cheniere Energy, Inc. 2008 Short-Term Retention Plan Restricted Stock Grant. (Incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on May 14, 2008)

10.97*†		Cheniere Energy, Inc. 2008 Long-Term Retention Plan. (Incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on May 14, 2008)

10.98*†		Form of Cheniere Energy, Inc. 2008 Long-Term Retention Plan Restricted Stock Grant. (Incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on May 14, 2008)

10.99*†		Form of Cheniere Energy, Inc. Amendment to Restricted Stock Grant under the 2008 Long-Term Retention Plan. (Incorporated by reference to Exhibit 10.95 to the Company's Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 3, 2011.

10.100*†		Cheniere Energy, Inc. 2008 Change of Control Cash Payment Plan. (Incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on May 14, 2008)

10.101*†		Form of Change of Control Agreement. (Incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on May 14, 2008)

10.102*†		Form of Release and Separation Agreement. (Incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on May 14, 2008)

10.103*†		Form of 2009 Phantom Stock Grant (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on February 27, 2009)

10.104*†		Form of Indemnification Agreement for directors of Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on December 19, 2008)



10.105*†		Form of Indemnification Agreement for officers of Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on April 6, 2009)

10.106*†		Charif Souki's U.K. Assignment Letter effective July 1, 2009 (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on July 2, 2009)

10.107*†		Charif Souki's Letter Agreement Amendment effective April 1, 2010. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on April 27, 2010)

10.108*†		Cheniere Energy, Inc. 2010 Goals & Bonus Plan. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on April 14, 2010)

10.109*†		Form of Long-Term Incentive Award - Restricted Stock Grant. (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on January 10, 2011)

10.110*†		Cheniere Energy, Inc. 2011 Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed on June 22, 2011)

10.111*†		Cheniere Energy, Inc. 2011 - 2013 Bonus Plan (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (SEC File No. 001-16383), filed March 8, 2011)

21.1		Subsidiaries of Cheniere Energy, Inc.

23.1		Consent of Ernst & Young LLP

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

* Incorporated by reference

† Management contract or compensatory plan or arrangement

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—

CHENIERE ENERGY, INC.

CONDENSED BALANCE SHEET

(in thousands)



	December 31,
	2011			2010
ASSETS
Debt receivable—affiliates	706,776			672,562
Other	293			795
Total assets	$	707,069		673,357

LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current accrued liabilities	$	1,920		1,956
Current debt	194,724			—
Current debt—affiliate	443,227			—
Long-term debt	—			179,129
Long-term debt—affiliate	—			405,035
Investment in and equity in losses of affiliates	240,190			559,847
Commitments and contingencies	—			—
Stockholders' deficit	(172,992		)	(472,610	)
Total liabilities and stockholders’ deficit	$	707,069		673,357

See accompanying notes to condensed financial statements.

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—

CHENIERE ENERGY, INC.

CONDENSED STATEMENT OF OPERATIONS

(in thousands)



	Year Ended December 31,
	2011			2010			2009
Revenues	$	—		$	—		$	—
Operating costs and expenses	(133		)	135			422
Gain (loss) from operations	133			(135		)	(422		)

Gain on early extinguishment of debt	—			—			45,362
Interest expense, net	(20,709		)	(19,112		)	(21,312		)
Interest income	—			—			12
Interest income—affiliates	34,213			22,778			34,213
Interest expense—affiliates	(38,192		)	(25,426		)	(38,192		)
Equity losses of affiliates	(174,201		)	(54,308		)	(181,151		)
Net loss	$	(198,756	)	$	(76,203	)	$	(161,490	)

See accompanying notes to condensed financial statements.

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—

CHENIERE ENERGY, INC.

CONDENSED STATEMENT OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2011			2010			2009
Net cash used in operating activitiies	$	(4,479	)	$	(27,531	)	$	(6,773	)

Cash flows from investing activities
Return of capital from (investments in) affiliates	(449,756		)	(18,934		)	28,635
Net cash provided by (used in) investing activities	$	(449,756	)	$	(18,934	)	$	28,635

Cash flows from financing activities
Purchase of treasury shares	(14,363		)	(2,844		)	(985		)
Repurchase of long-term debt	—			—			(30,029		)
Sale of common stock	468,598			49,308			—
Issuance of restricted stock	—			1			—
Net cash provided by (used in) financing activities	$	454,235		$	46,465		$	(31,014	)

Net decrease in cash and cash equivalents	—			—			(9,152		)
Cash and cash equivalents—beginning of year	—			—			9,152
Cash and cash equivalents—end of year	$	—		$	—		$	—

See accompanying notes to condensed financial statements

100

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—

CHENIERE ENERGY, INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The condensed financial statements represent the financial information required by Securities and Exchange Commission Regulation S-X 5-04 for Cheniere Energy, Inc ("Cheniere").

In the condensed financial statements, Cheniere’s investments in affiliates are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are recorded in the balance sheet. The loss from operations of the affiliates is reported on a net basis as equity in net losses of affiliates.

A substantial amount of Cheniere’s operating, investing, and financing activities are conducted by its affiliates. The condensed financial statements should be read in conjunction with Cheniere’s consolidated financial statements.

NOTE 2—DEBT

As of December 31, 2011 and 2010, our debt consisted of the following (in thousands):



	December 31,
	2011			2010
Current debt (including affiliate)
Note—Affiliate	$	443,227		$	—
Convertible Senior Unsecured Notes	204,630			—
Total current debt	647,857			—
Current debt discount
Convertible Senior Unsecured Notes	(9,906		)	—
Total current debt, net of discount	$	637,951		$	—

Long-term debt (including affiliate)
Long-term Note—Affiliate	$	—		$	405,035
Convertible Senior Unsecured Notes	—			204,630
Total long-term debt	—			609,665
Long-term debt discount
Convertible Senior Unsecured Notes	—			(25,501		)
Total long-term debt (including affiliate), net of discount	$	—		$	584,164

Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2011 (in thousands):



	Payments Due for Years Ended December 31, (1)
	Total		2012		2013 to 2014		2015 to 2016		Thereafter
Note—Affiliate	$	443,227	$	443,227	$	—	$	—	$	—
Convertible Senior Unsecured Notes	$	204,630	$	204,630	$	—	$	—	$	—
Total	$	647,857	$	647,857	$	—	$	—	$	—


(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.

101

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—

CHENIERE ENERGY, INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

Note—Affiliate

In May 2007, we entered into a $391.7 million long-term note ("Note—Affiliate") with Cheniere Subsidiary Holdings, LLC ("Cheniere Subsidiary"), a wholly owned subsidiary of Cheniere. Cheniere Subsidiary received the $391.7 million net proceeds from a $400 million credit agreement entered into in May 2007. Borrowings under the Note—Affiliate bear interest equal to the terms of Cheniere Subsidiary's credit agreement at a fixed rate of 9¾% per annum. Interest is calculated on the unpaid principal amount of the Note—Affiliate outstanding and is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year. The Note—Affiliate will mature on May 31, 2012. In August 2008, the Note—Affiliate was replaced with a global intercompany note entered into by all Cheniere subsidiaries that were parties to the 2008 Loans. Each subsidiary is both a maker and a payee under the global intercompany note, and balances between subsidiaries are as recorded on Cheniere's books and records. The $391.7 million of proceeds from the Note—Affiliate were used for general corporate purposes, including our repurchase, completed during 2007, of approximately 9.2 million shares of our outstanding common stock pursuant to the exercise of the call options acquired in the issuer call spread purchased by us in connection with the issuance of the Convertible Senior Unsecured Notes.

NOTE 3—GUARANTEES

Guarantees on Behalf of Cheniere Marketing, LLC

Marketing and Trading Guarantees

Our LNG and natural gas marketing business segment is pursuing a two-front commercial strategy focused on producing long-term recurring cash flow by capitalizing on 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal reserved by Cheniere Energy Investments, LLC ("Cheniere Investments"). Our strategy is to remain engaged in the LNG spot market as opportunities arise, and to maintain relationships with key suppliers and market participants that we believe are candidates for entering into long-term LNG cargo sales and/or the purchase of TUA capacity currently reserved by Cheniere Investments. Many of Cheniere Marketing, LLC’s natural gas purchase, sale, transportation and shipping agreements have been guaranteed by Cheniere. As of December 31, 2011, these contracts have been guaranteed by Cheniere and have zero amount of exposure to the potential of future payments. There was zero carrying amount of liability related to these guaranteed contracts as of December 31, 2011.

Guarantee on behalf of Sabine Pass Tug Services, LLC

Sabine Pass Tug Services, LLC ("Tug Services"), a wholly owned subsidiary of Cheniere Energy Partners, L.P., entered into a Marine Services Agreement ("Tug Agreement") for three tugs with Alpha Marine Services, LLC. The initial term of the Tug Agreement ends on the tenth anniversary of the service date, with Tug Services having the option for two additional extension terms of five years each. This contract has been guaranteed by Cheniere for up to $5.0 million.

NOTE 4 —SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS



	Year Ended December 31,
	2011			2010			2009
	(in thousands)
Non-cash capital contributions (1)	$	(174,201	)	$	(54,308	)	$	181,151


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

102

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities 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.
	(Registrant)

	By:	/s/ CHARIF SOUKI
		Charif Souki Chief Executive Officer, President and Chairman of the Board
	Date:	February 24, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date

/s/ CHARIF SOUKI	Chief Executive Officer, President & Chairman of the Board (Principal Executive Officer)	February 24, 2012
Charif Souki		February 24, 2012

/s/ MEG A. GENTLE	Senior Vice President & Chief Financial Officer (Principal Financial Officer)	February 24, 2012
Meg A. Gentle		February 24, 2012

/s/ JERRY D. SMITH	Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 24, 2012
Jerry D. Smith		February 24, 2012

/s/ VICKY A. BAILEY	Director	February 24, 2012
Vicky A. Bailey	Director	February 24, 2012

/s/ NUNO BRANDOLINI	Director	February 24, 2012
Nuno Brandolini	Director	February 24, 2012

/s/ KEITH F. CARNEY	Director	February 24, 2012
Keith F. Carney	Director	February 24, 2012

/s/ JOHN M. DEUTCH	Director	February 24, 2012
John M. Deutch	Director	February 24, 2012

/s/ PAUL J. HOENMANS	Director	February 24, 2012
Paul J. Hoenmans	Director	February 24, 2012

/s/ DAVID B. KILPATRICK	Director	February 24, 2012
David B. Kilpatrick	Director	February 24, 2012

/s/ G. ANDREA BOTTA	Director	February 24, 2012
G. Andrea Botta	Director	February 24, 2012

/s/ WALTER L. WILLIAMS	Director	February 24, 2012
Walter L. Williams	Director	February 24, 2012

103