10-K

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, 2012

OR

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. 001-33366

CHENIERE ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	20-5913059
(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 Units Representing Limited Partner Interests	NYSE MKT
(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.    YesoNox

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.    YesoNox

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.    YesxNoo

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).    YesxNoo

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  o	Accelerated filer  x
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).    YesoNox

The aggregate market value of the registrant’s Common Units held by non-affiliates of the registrant was approximately $439 million as of June 30, 2012.

The issuer had 39,488,488 common units, 133,333,334 Class B units and 135,383,831 subordinated units outstanding as of February 13, 2013.

Documents incorporated by reference: None

CHENIERE ENERGY PARTNERS, L.P

TABLE OF CONTENTS

PART I	1
Items 1. and 2. Business and Properties	1
General	1
Our Business Strategy	2
Our Business	2
Market Factors and Competition	8
Subsidiaries	9
Employees and Labor Relations	9
Available Information	9
Item 1A. Risk Factors	11
Risks Relating to Our Financial Matters	11
Risks Relating to Our Business	13
Risks Relating to Our Cash Distributions	23
Risks Relating to an Investment in Us and Our Common Units	25
Risks Relating to Tax Matters	30
Item 1B. Unresolved Staff Comments	33
Item 3. Legal Proceedings	33
Item 4. Mine Safety Disclosure	33
PART II	33
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	33
Item 6. Selected Financial Data	38
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation	39
Introduction	39
Overview of Business	39
Overview of Significant Events	39
Liquidity and Capital Resources	40
Contractual Obligations	47
Results of Operations	48
Off-Balance Sheet Arrangements	49
Summary of Critical Accounting Policies and Estimates	49
Recent Accounting Standards	52
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	53
Item 8. Financial Statements and Supplementary Data	54
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	89
Item 9A. Controls and Procedures	89
Item 9B. Other Information	89
PART III	91
Item 10. Directors, Executive Officers of Our General Partner and Corporate Governance	91
Item 11. Executive Compensation	94
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Unitholder Matters	97
Item 13. Certain Relationships and Related Transactions, and Director Independence	99
Item 14. Principal Accountant Fees and Services	101
PART IV	101
Item 15. Exhibits and Financial Statement Schedules	101

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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 regarding our ability to pay distributions to our unitholders; 

• statements regarding our expected receipt of cash distributions from Sabine Pass LNG, L.P. ("Sabine Pass LNG") or Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"); 

• statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of liquefied natural gas ("LNG") imports into or exports from North America and other countries worldwide, regardless of the source of such information, or the transportation or demand for and prices related to natural gas, LNG or other hydrocarbon products;

• statements regarding any financing transactions or arrangements, or ability to enter into such transactions;

• statements relating to the construction of our Trains, including statements concerning the engagement of any engineering, procurement and construction ("EPC") contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;

• statements regarding any agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, liquefaction or storage capacities that are, or may become subject to contracts;

• statements regarding counterparties to our commercial contracts, construction contracts and other contracts;

• statements regarding our planned construction of additional Trains, including the financing of such Trains;

• statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;

• statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections or objectives, including anticipated 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.

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DEFINITIONS

In this annual report, unless the context otherwise requires: 

• Bcf means billion cubic feet;

• Bcf/d means billion cubic feet per day;

• Bcfe means billion cubic feet of natural gas equivalent using the ratio of six thousand cubic feet of natural gas to one barrel (or 42 U.S. gallons liquid volume) of crude oil, condensate and natural gas liquids;

• cm means cubic meter;

• Dthd means dekatherms per day which is equivalent to one million British thermal units or one MMBtu per day;

• EPC means engineering, procurement and construction;

• Henry Hub means the final settlement price (in USD per MMBtu) for the New York Mercantile Exchange's Henry Hub natural gas futures contract for the month in which a relevant cargo's delivery window is scheduled to begin;

• LNG means liquefied natural gas;

• MMBtu means million British thermal units;

• mmtpa means million metric tons per annum;

• SPA means a LNG sale and purchase agreement;

• Tcf means trillion cubic feet;

• Train means a natural gas liquefaction train; and

• TUA means terminal use agreement.

PART I

ITEMS 1. and 2.     BUSINESS AND PROPERTIES

General

We are a Delaware limited partnership formed by Cheniere Energy, Inc. ("Cheniere"). Through our wholly owned subsidiary, Sabine Pass LNG, we own and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels of up to 265,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Approximately one-half of the LNG receiving capacity at the Sabine Pass LNG terminal is contracted to two multinational energy companies. We are developing natural gas liquefaction facilities (the "Liquefaction Project") at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, Sabine Pass Liquefaction. Unless the context requires otherwise, references to "Cheniere Partners", "we", "us" and "our" refer to Cheniere Energy Partners, L.P. and its subsidiaries, including Sabine Pass LNG and Sabine Pass Liquefaction. 

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The following diagram depicts our abbreviated capital structure, including our ownership of Sabine Pass LNG and Sabine Pass Liquefaction as of February 13, 2013:

LNG is natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to justify economically the use of LNG. LNG is transported using large oceangoing LNG tankers specifically constructed for this purpose. LNG receiving terminals offload LNG from LNG tankers, store the LNG prior to processing, heat the LNG to return it to a gaseous state and deliver the resulting natural gas into pipelines for transportation to market.

Our Business Strategy

Our primary business strategy is to develop, construct, and operate assets supported by long-term, fixed fee contracts. We plan to implement our strategy by:

• completing construction and commencing operation of our Trains (each in sequence, "Train 1", "Train 2", "Train 3", "Train 4", "Train 5" and "Train 6");

• developing and operating our Trains safely, efficiently and reliably;

• making LNG available to our long-term SPA customers to generate steady and reliable revenues and operating cash flows;

• safely maintaining and operating the Sabine Pass LNG terminal;

• utilizing capacity at the Sabine Pass LNG terminal for short-term and spot LNG purchases and sales until such capacity is used in connection with the 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

• expanding our existing asset base through acquisitions from Cheniere or third parties or our own development of the Liquefaction Project or complementary businesses or assets such as other LNG terminals, natural gas storage assets and natural gas pipelines.

Our Business

We have constructed and are operating the Sabine Pass LNG terminal located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. We have long-term leases for five tracts of land consisting of 1,044 acres. We are currently operating LNG receiving facilities at the terminal and are developing and constructing the Liquefaction Project.

Regasification Facilities

The regasification facilities at the Sabine Pass LNG terminal have operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. 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: 

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• Total Gas & 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.

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by Sabine Pass Liquefaction. Sabine Pass Liquefaction is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year, continuing until at least 20 years after Sabine Pass Liquefaction delivers its first commercial cargo at Sabine Pass Liquefaction's facilities under construction, which may occur as early as late 2015. Sabine Pass Liquefaction obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Energy Investments, LLC ("Cheniere Investments"), a wholly owned subsidiary of Cheniere Partners, of its rights, title and interest under its TUA. In connection with the assignment, Sabine Pass Liquefaction, Cheniere Investments and Sabine Pass LNG entered into a terminal use rights assignment and agreement ("TURA") pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to Sabine Pass LNG. In an effort to monetize Cheniere Investments' reserved capacity under its TURA during construction of the Liquefaction Project, Cheniere Marketing, LLC ("Cheniere Marketing"), a wholly owned subsidiary of Cheniere, has entered into a variable capacity rights agreement ("VCRA") pursuant to which 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. The revenue earned by Sabine Pass LNG from the capacity payments made under the TUA and the revenue earned by Cheniere Investments under the VCRA are eliminated upon consolidation of our financial statements. We have guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA.

In September 2012, Sabine Pass Liquefaction entered into a partial TUA assignment agreement with Total, whereby Sabine Pass Liquefaction will progressively gain access to Total's capacity and other services provided under Total's TUA with Sabine Pass LNG.  This agreement will provide Sabine Pass Liquefaction with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Train 5 and Train 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of Train 3, and permit Sabine Pass Liquefaction to more flexibly manage its LNG storage capacity with the commencement of Train 1. Notwithstanding any arrangements between Total and Sabine Pass Liquefaction, payments required to be made by Total to Sabine Pass LNG shall continue to be made by Total to Sabine Pass LNG in accordance with its TUA.

Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.

Liquefaction Facilities

The Liquefaction Project is being developed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We plan to construct up to six Trains, which are in various stages of development. We have commenced construction of Train 1 and Train 2 and the related new facilities needed to treat, liquefy, store and export natural gas. Construction of Train 3 and Train 4 and the related facilities is expected to commence upon, among other things, obtaining financing commitments sufficient to fund construction of such Trains and making a positive final investment decision. We recently began the development of Train 5 and Train 6 and expect to commence the regulatory approval process in the first half of 2013.

The Trains are being designed, constructed and commissioned by Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") using the ConocoPhillips Optimized Cascade® technology, a proven technology deployed in numerous LNG projects around the world. Sabine Pass Liquefaction has entered into lump sum turnkey contracts for the engineering, procurement and construction of Train 1 and Train 2 (the "EPC Contract (Train 1 and 2)") and Train 3 and Train 4 (the "EPC Contract (Train 3 and 4)", and together with the EPC Contract (Train 1 and 2), the "EPC Contracts"), with Bechtel in November 2011 and December 2012, respectively.

In August 2012, we received a final order from the U.S. Department of Energy ("DOE") to export 16 mmtpa of LNG to all nations with which trade is permitted.  In April 2012, we received authorization from the Federal Energy Regulatory Commissin ("FERC") to site, construct and operate Train 1, Train 2, Train 3 and Train 4.

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As of December 31, 2012, the overall project completion for Train 1 and Train 2 was approximately 18% complete. Based on our current construction schedule, we anticipate that Train 1 will produce LNG as early as the end of 2015.

Customers

As of February 13, 2013, Sabine Pass Liquefaction has entered into the following third-party SPAs:

• BG Gulf Coast LNG, LLC ("BG") SPA commences upon the date of first commercial delivery for Train 1 and includes an annual contract quantity of 182,500,000 MMBtu of LNG and a fixed fee of $2.25 per MMBtu and includes additional annual contract quantities of 36,500,000 MMBtu, 34,000,000 MMBtu, and 33,500,000 MMBtu upon the date of first commercial delivery for Train 2, Train 3 and Train 4, respectively, with a fixed fee of $3.00 per MMBtu. The total expected annual contracted cash flow from BG from the fixed fee component is $723 million. In addition, Sabine Pass Liquefaction has agreed to make LNG available to BG to the extent that Train 1 becomes commercially operable prior to the beginning of the first delivery window. The obligations of BG are guaranteed by BG Energy Holdings Limited, a company organized under the laws of England and Wales, with a credit rating of A2/A.

• Gas Natural Aprovisionamientos SDG S.A. ("Gas Natural Fenosa"), an affiliate of Gas Natural SDG, S.A., SPA commences upon the date of first commercial delivery for Train 2 and includes an annual contract quantity of 182,500,000 MMBtu of LNG and a fixed fee of $2.49 per MMBtu, equating to expected annual contracted cash flow from the fixed fee component of $454 million. The obligations of Gas Natural Fenosa are guaranteed by Gas Natural SDG S.A., a company organized under the laws of Spain, with a credit rating of Baa2/BBB.

• Korea Gas Corporation ("KOGAS") SPA commences upon the date of first commercial delivery for Train 3 and includes an annual contract quantity of 182,500,000 MMBtu of LNG and a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of $548 million. KOGAS is organized under the laws of the Republic of Korea, with a credit rating of A/A1.

• GAIL (India) Limited ("GAIL") SPA commences upon the date of first commercial delivery for Train 4 and includes an annual contract quantity of 182,500,000 MMBtu of LNG and a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of $548 million. GAIL is organized under the laws of India, with a credit rating of Baa2/BBB-.

• Total, an affiliate of Total S.A., SPA commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 104,750,000 MMBtu of LNG and a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of $314 million. The obligations of Total are guaranteed by Total S.A., a company organized under the laws of France, with a credit rating of Aa1/AA.

In aggregate, the fixed fee portion to be paid by these customers is approximately $2.6 billion annually, with fixed fees starting from the commencement of operations of Train 1, Train 2, Train 3, Train 4 and Train 5 equating to $411 million, $564 million, $650 million, $648 million and $314 million, respectively.

In addition, Cheniere Marketing has entered into an SPA to purchase, at its option, any excess LNG produced that is not committed to non-affiliate parties, for up to a maximum of 104,000,000 MMBtu per annum produced from Train 1 through Train 4. Cheniere Marketing may purchase incremental LNG volumes at a price of 115% of Henry Hub plus up to $3.00 per MMBtu for the first 36,000,000 MMBtu of the most profitable cargoes sold each year by Cheniere Marketing, and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing.

Construction

In November 2011, Sabine Pass Liquefaction entered into the EPC Contract (Train 1 and 2) with Bechtel. Sabine Pass Liquefaction issued a notice to proceed for construction under the EPC Contract (Train 1 and 2) in August 2012.

In December 2012, Sabine Pass Liquefaction entered into the EPC Contract (Train 3 and 4) with Bechtel. Under the EPC Contract (Train 3 and 4), if Sabine Pass Liquefaction fails to issue notice to proceed to Bechtel by December 31, 2013, then either Sabine Pass Liquefaction or Bechtel may terminate the EPC Contract (Train 3 and 4), and Bechtel will be paid costs reasonably incurred on account of such termination and a lump sum of $5.0 million. The Trains are in various stages of development, as described above.

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The contract price of the EPC Contract (Train 1 and 2) is approximately $3.97 billion, reflecting amounts incurred under change orders through December 31, 2012. Total expected capital costs for Train 1 and Train 2 are estimated to be between $4.5 billion and $5.0 billion before financing costs, including estimated owner's costs and contingencies. Budgeted total all-in costs for Train 1 and Train 2 are estimated to be between $5.5 billion and $6.0 billion, including financing costs and interest expense during construction. The contract price of the EPC Contract (Train 3 and 4) is $3.77 billion, only subject to adjustment by change order (including if Sabine Pass Liquefaction issues the notice to proceed after June 1, 2013). The cost to construct Train 3 and Train 4 is currently estimated to be between $4.5 billion and $5.0 billion before financing costs, including estimated owner's costs and contingencies.

The liquefaction technology to be employed under the EPC Contracts is the ConocoPhillips Optimized Cascade® Process, which was first used at the ConocoPhillips Petroleum Kenai plant built by Bechtel in 1969 in Kenai, Alaska. Bechtel has since designed and/or constructed LNG facilities using the ConocoPhillips Optimized Cascade® technology in Angola, Australia, Egypt, Equatorial Guinea and Trinidad. The design and technology has been proven in over four decades of operation.

Pipeline Facilities

Cheniere Creole Trail Pipeline, L.P. ("Creole Trail"), an indirect wholly owned subsidiary of Cheniere, owns the Creole Trail Pipeline, a 94-mile pipeline interconnecting the Sabine Pass LNG terminal with a number of large interstate pipelines, including Natural Gas Pipeline Company of America, Transcontinental Gas Pipeline Corporation, Tennessee Gas Pipeline Company, Florida Gas Transmission Company, Texas Eastern Gas Transmission, and Trunkline Gas Company, as well as the intrastate pipeline system of Bridgeline Holdings, L.P.

Sabine Pass Liquefaction has entered into a transportation precedent agreement to secure firm pipeline transportation capacity with Creole Trail and two other pipelines for Train 1 and Train 2. Creole Trail filed an application with the FERC in April 2012 for certain modifications to allow the Creole Trail Pipeline to be able to transport natural gas to the Sabine Pass LNG terminal. Creole Trail estimates the capital costs to modify the Creole Trail Pipeline will be approximately $90 million. The modifications are expected to be in service in time for the commissioning and testing of Train 1 and Train 2.

We have entered into an agreement with Cheniere to purchase the equity interests of the entities that own the Creole Trail Pipeline if, among other things, we obtain acceptable financing for the purchase price. The consideration to be paid by us for the Creole Trail Pipeline is 12 million Class B units and $300 million, plus any costs incurred by Creole Trail from August 2012 until the purchase date, including, if applicable, any portion of the expected $90 million for pipeline modifications.

LNG Terminal Governmental Regulation

The Sabine Pass LNG terminal and Liquefaction Project operations and construction 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 our cost of operations and construction, and failure to comply with such laws could result in substantial penalties.

Federal Energy Regulatory Commission ("FERC")

The design, construction and operation of our proposed liquefaction facilities, and the export of LNG, are highly regulated activities. In order to site and construct the Sabine Pass LNG terminal, we received and are required to maintain authorization from the FERC under Section 3 of the Natural Gas Act of 1938, as amended ("NGA"). 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 site, construct and operate our liquefaction facilities.

The Energy Policy Act of 2005 ("EPAct"), amended Section 3 of the NGA to establish or clarify the FERC's exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, although except as specifically provided in the EPAct, nothing in the EPAct is intended to affect otherwise applicable law related to any other federal agency's authorities or responsibilities related to LNG terminals. Sabine Pass Liquefaction filed an application with the FERC in January 2011 for an order under Section 3 of the NGA authorizing the siting, construction and operation of the Liquefaction Project, including the siting, construction and operation of Train 1 through Train 4. The FERC issued final orders in April and July

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2012 approving Sabine Pass Liquefaction's application. Subsequently, the FERC issued written approval to commence site preparation work for Train 1 through Train 4. The FERC approval requires Sabine Pass Liquefaction to obtain certain additional FERC approvals as construction progresses. To date Sabine Pass Liquefaction has been able to obtain these approvals as needed. In October 2012, Sabine Pass Liquefaction filed an application at the FERC to amend its orders to reflect certain modifications of the Liquefaction Project. The pending modifications will require additional review by the FERC under the National Environmental Policy Act ("NEPA"), which will include preparation and evaluation of a supplemental Environmental Assessment for the project. The need for this approval has not materially affected Sabine Pass Liquefaction's construction progress. Sabine Pass Liquefaction will also need the FERC's approval to construct Train 5 and Train 6, which have not yet been authorized at this time. Throughout the life of our proposed liquefaction facilities, we 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.

The EPAct amended the NGA to prohibit market manipulation, and increased civil and criminal penalties for any violations of the NGA 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.

DOE Export License

The DOE has issued two orders authorizing exports from the Liquefaction Project: an order authorizing the export of up to the equivalent of 16 mmtpa (approximately 803 Bcf) of domestically produced LNG by vessel from the Sabine Pass LNG terminal to countries with which the United States has a Free Trade Agreement providing for national treatment for trade in natural gas ("FTA") 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 mmtpa) 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 August 7, 2017.

Exports of natural gas to countries with which the United States has an FTA are "deemed to be consistent with the public interest" and authorization to export LNG to FTA countries shall be granted by the DOE without "modification or delay". Sabine Pass Liquefaction received approval to export to FTA countries in September 2010. FTA countries which import LNG now or will do so by 2016 include: Chile, Mexico, Singapore, South Korea and the Dominican Republic.

Exports of natural gas to countries with which the United States does not have an FTA are considered by DOE in the context of a comment period whereby interveners are provided the opportunity to assert that such authorization would not be consistent with the public interest. Sabine Pass Liquefaction received final approval to export to non-FTA countries in August 2012.

Other Governmental Permits, Approvals and Authorizations

The operation of the Sabine Pass LNG terminal and related projects, and the construction and operation of our proposed liquefaction facilities, are also subject to additional federal permits, orders, approvals and consultations required by other federal agencies, including: the 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, EPA and U.S. Department of Homeland Security.

Three significant permits are the U.S. Army Corps of Engineers ("USACE") Section 404 of the Clean Water Act/Section 10 of the Rivers and Harbors Act Permit (the "Section 10/404 Permit"), the Clean Air Act Title V Operating Permit and the Prevention of Significant Deterioration (PSD) Permit, the latter two permits issued by the Louisiana Department of Environmental Quality ("LDEQ").

The application for revision of the Sabine Pass LNG terminal's Section 10/404 Permit to authorize construction of Train 1 through Train 4 was submitted in January 2011. The process included a public comment period which commenced in March 2011 and closed in April 2011. The revised Section 10/404 permit was received from the USACE in March 2012. The USACE acted in the capacity as a cooperating agency in the FERC's NEPA review process. The application to amend the Sabine Pass LNG terminal's existing Title V and PSD permits to authorize construction of Train 1 through Train 4 was initially submitted in December 2010 and revised in March 2011. The process included a public comment period from June 2011 to August 2011 and a public

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hearing in August 2011. The final revised Title V and PSD permits were issued by the LDEQ in December 2011. Although this permit is final, a petition with the EPA has been filed pursuant to the Clean Air Act requesting that the EPA object to the Title V permit. EPA has not ruled on this petition. In June 2012, we applied to the LDEQ for a further amendment to the Title V and PSD permits to reflect the proposed modifications to the Liquefaction Project that were filed with the FERC in October 2012 as discussed above. In November 2012, the LDEQ issued proposed revised air permits for public comment, and comments regarding the proposed revised air permits have been filed. We anticipate, but cannot guarantee, that the revised Title V and PSD permits will be issued during the first quarter of 2013.

We will also need to obtain a modification to the Sabine Pass LNG terminal's existing wastewater discharge permit to authorize discharges from the liquefaction facilities prior to the commencement of operation of the Liquefaction Project.

The Sabine Pass LNG terminal regasification and liquefaction facilities are 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.

Commodity Futures Trading Commission

Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), is designed primarily to (1) regulate certain participants in the swaps markets, including new entities defined as "Swap Dealers" and "Major Swap Participants," (2) require clearing and exchange-trading of certain swaps that the Commodities Futures Trading Commission (the "CFTC") determines must be cleared, (3) increase swap market transparency through robust reporting and recordkeeping requirements, and (4) enhance the CFTC's rulemaking and enforcement authority, including the authority to establish position limits on swaps products. This legislation requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the Dodd-Frank Act. In November 2011, the CFTC adopted rules to impose new position limits on certain core futures and equivalent swaps contracts for physical commodities, including natural gas, with exceptions for certain bona fide hedging transactions. These new position limit rules were vacated by a federal district court in September 2012, and the CFTC has appealed this ruling. Consequently, the CFTC's vacated position limits rules will not go into effect unless and until the CFTC prevails on appeal of this ruling or issues and finalizes revised rules.

In October 2012, the CFTC's and SEC's joint rules further defining the term "swap" became effective, which triggered the start of certain Dodd-Frank Act regulatory obligations. The CFTC's swaps reporting and recordkeeping rules are to be phased in over 180 days following October 12, 2012, depending on swap asset class and counterparty. It is expected that entities that are end users of swaps or otherwise are not swap dealers or major swap participants will be required to comply with the Dodd-Frank Act reporting and recordkeeping rules in April 2013. In December 2012, the CFTC published final rules regarding mandatory clearing of certain interest rate swaps and certain index credit default swaps and setting compliance dates for different categories of market participants, the earliest of which is March 11, 2013. The CFTC has not yet proposed any rules requiring the clearing of any other classes of swaps, including physical commodity swaps. Although we expect to qualify for the end-user exception from the clearing requirement for our swaps, mandatory clearing requirements applicable to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. For uncleared swaps, the Dodd-Frank Act may also require our counterparties to require that we enter into credit support documentation and/or initial and variation margin requirements; however, the CFTC's and other agencies' margin rules are not yet final and therefore the application of those provisions to us is uncertain at this time. The financial reform legislation may also cause our derivatives counterparties to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation, and any additional regulations, may also adversely affect our existing derivative contracts and restrict our ability to monetize such contracts, cause us to restructure certain contracts, reduce the availability of derivatives to protect against risks or to optimize assets, and impact the liquidity of certain swaps products, all of which could increase our business costs.

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

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types, quantities and concentration of substances that can be released into the environment and can lead to substantial civil and criminal fines and penalties for non-compliance.

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 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.

In 2009, the EPA promulgated and finalized the Mandatory Greenhouse Gas Reporting Rule for multiple sections of the economy. This rule requires mandatory reporting of greenhouse gas ("GHG") emissions from stationary fuel combustion sources as well as all fugitive emissions throughout LNG terminals. From time to time, Congress has considered proposed legislation directed at reducing GHG emissions, and the EPA has defined GHG emissions thresholds for requiring certain permits for new and existing industrial sources. It is not possible at this time to predict how future regulations or legislation may address GHG 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 review and possible 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 General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act ("CWA")

The Sabine Pass LNG terminal operations and the proposed liquefaction facilities are subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained to discharge pollutants into state and federal waters. The CWA is administered by the EPA, the USACE, and by the states (in Louisiana, by the LDEQ, and in Texas, by the Texas Commission on Environmental Quality).

Resource Conservation and Recovery Act ("RCRA")

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

Endangered Species Act

The Sabine Pass LNG terminal operations and the proposed liquefaction facilities may be restricted by requirements under the Endangered Species Act, which seeks to protect endangered or threatened animal, fish and plant species and designated habitats.

Market Factors and Competition

Sabine Pass LNG currently does not experience competition for its terminal capacity because the entire approximately 4.0 Bcf/d of regasification capacity that is available at the Sabine Pass LNG terminal has been fully contracted. If and when Sabine Pass LNG has to replace any TUAs, it will compete with other then-existing LNG terminals for customers.

The Liquefaction Project currently does not experience competition with respect to Train 1 through Train 4, and a portion of Train 5. Sabine Pass Liquefaction has entered into five fixed price, 20-year LNG SPAs that will utilize substantially all of the

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liquefaction capacity available from these Trains. Each customer will be required to pay an escalating fixed fee for its annual contract quantity even if it elects not to purchase any LNG from us.

If and when Sabine Pass Liquefaction needs to replace any existing SPA or enter into new SPAs with respect to Train 5 and Train 6, Sabine Pass Liquefaction will compete on the basis of price per contracted volume of LNG with other LNG liquefaction projects throughout the world. Revenues associated with any incremental volumes of the Liquefaction Project, including those under the Cheniere Marketing SPA discussed above, will also be subject to market-based price competition.

Our ability to sell any seasonal quantities of LNG available from Train 1 through Train 4, develop additional Trains, 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, crude 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 and LNG to grow significantly as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Global demand for natural gas is projected by the International Energy Agency to grow by more than 24 Tcf between 2010 and 2020, fueled by the growth of emerging economies. Global demand for LNG is forecast to increase by 49%, or 5.7 Tcf, by 2020 and reach a total of 456 mmtpa, or 22.2 Tcf, by 2025. LNG is substantially more flexible than pipeline-delivered natural gas. As a result, the share of LNG in the global natural gas market is expected to increase as markets seek to improve security of supply by accessing a wide portfolio of producers that can readjust deliveries to meet the needs of changing markets.

While global natural gas consumption has been rising internationally, natural gas production in the United States 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.

Our ability to continue to develop new facilities in the United States will be driven in part by the continued success of the North American upstream natural gas sector in developing new reservoirs, continuing to drive down costs and producing 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 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 than competing projects. Furthermore, because natural gas is purchased from the United States market at a Henry Hub related price, we can offer LNG for sale at an alternative price to crude oil prices, thereby providing customers with an opportunity to diversify their supply portfolios by geography and price index.

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 and the Liquefaction Project.

Employees and Labor Relations

We have no employees. We rely on our general partner to manage all aspects of the operation, maintenance and construction of the Sabine Pass LNG terminal, the Liquefaction Project and the conduct of our business. Because our general partner has no employees, it relies on subsidiaries of Cheniere to provide the personnel necessary to allow it to meet its management obligations to us, Sabine Pass LNG and Sabine Pass Liquefaction. As of February 13, 2013, Cheniere and its subsidiaries had 306 full-time employees, including 163 employees who directly supported the Sabine Pass LNG terminal operations and the Liquefaction Project. See Note 13—"Related Party Transactions" in our Notes to Consolidated Financial Statements for a discussion of these arrangements.  Cheniere considers its current employee relations to be favorable.

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Available Information

Our common units have been publicly traded since March 21, 2007, and are traded on the NYSE MKT under the symbol "CQP". 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.cheniereenergypartners.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 unitholder, 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 Partners, L.P, 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 and other information regarding issuers, like us, that file electronically with the SEC.

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ITEM 1A.                      RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. 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, contracts, financial condition, operating results, cash flows, 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 Business; 

• Risks Relating to Our Cash Distributions; 

• Risks Relating to an Investment in Us and Our Common Units; and 

• Risks Relating to Tax Matters.

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, 2012, we had $419.3 million of cash and cash equivalents and $364.9 million of restricted cash and cash equivalents, and we had $2.2 billion of total debt outstanding on a consolidated basis (before debt discounts). In addition, in February 2013, we issued an additional $1.5 billion of indebtedness to finance the capital costs in connection with the construction of Train 1 and Train 2. We incur significant interest expense relating to the assets at the Sabine Pass LNG terminal and Liquefaction Project, and we anticipate needing to incur substantial additional debt and issue equity to finance the construction of all six trains of the Liquefaction Project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access capital markets. Furthermore, 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 $150.1 million and $31.0 million for the years ended December 31, 2012 and 2011, respectively. In addition, our net cash flow used in operating activities was $26.2 million for the year ended December 31, 2012. 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 addition, we will continue to incur significant capital and operating expenditures while we develop and construct the Liquefaction Project. We currently expect that we will not begin to receive cash flows from operations under any SPA until the end of 2015, at the earliest. Any delays beyond the expected development periods for Train 1 would prolong, and could increase the level of, our operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully and timely complete the applicable Train.

In order to generate needed amounts of cash, we may sell equity or equity-related securities, including additional common units. Such sales could dilute our unitholders' proportionate indirect interests in our assets, business operations, Liquefaction Project and other projects, and could adversely affect the market price of our common units.

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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. Such sales, in one or more transactions, could dilute our unitholders' proportionate indirect interests in our assets, business operations and proposed projects, including the Liquefaction Project. In addition, such sales, or the anticipation of such sales, could adversely affect the market price of our common units.

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, KOGAS, GAIL and Total, each of which has entered into an SPA with Sabine Pass Liquefaction and agreed to pay us approximately $723 million, $454 million, $548 million, $548 million and $314 million annually, respectively. We are dependent on each customer's continued willingness and ability to perform its obligations under its SPA. We are also exposed to the credit risk of any guarantor of these customers' obligations under their respective TUA or SPA in the event that we must seek recourse under a guaranty. If any customer fails to perform its obligations under its TUA or SPA, our business, contracts, financial condition, operating results, cash flow, liquidity 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 TUA or SPA.

Each of our customer contracts is subject to termination under certain circumstances.

Each of Sabine Pass LNG's long-term TUAs contains various termination rights. For example, each customer 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. Sabine Pass LNG may not be able to replace these TUAs on desirable terms, or at all, if they are terminated.

Each of Sabine Pass Liquefaction's SPAs contain various termination rights allowing our customers to terminate their SPAs including, without limitation: (i) upon the occurrence of certain events of force majeure; (ii) if we fail to make available specified scheduled cargo quantities; (iii) delays in the commencement of commercial operations; and (iv) if the conditions precedent contained in the SPAs are not met or waived by specified dates. We may not be able to replace these SPAs on desirable terms, or at all, if they are terminated.

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 purchase of natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange 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.

The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

The enactment of the Dodd-Frank Act could have an adverse impact on our ability to hedge risks associated with our business.

Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the OTC derivatives market and entities, such as us, that participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), requires the Commodities Futures Trading Commission (the

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"CFTC") and the SEC to promulgate certain rules and regulations, including relating to the regulation of certain swaps entities, the clearing of certain swaps, and the reporting and recordkeeping of swaps, and gave the CFTC the authority to establish position limits. Although the CFTC established position limits on certain core futures and equivalent swaps contracts for physical commodities, including natural gas, with exceptions for certain bona fide hedging transactions, those limits were vacated by federal district court in September 2012 and will not go into effect unless and until the CFTC prevails on appeal of this ruling or issues and finalizes revised rules.

In December 2012, the CFTC published final rules regarding mandatory clearing of certain interest rate swaps and certain index credit default swaps and setting compliance dates for different categories of market participants, the earliest of which is March 2013. The CFTC has not yet proposed any rules requiring the clearing of any other classes of swaps, including physical commodity swaps. Although we expect to qualify for the end-user exception from the clearing requirement for our swaps, mandatory clearing requirements applicable to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or other regulators may require our counterparties to require that we enter into credit support documentation and/or post initial and variation margin as collateral; however, the proposed margin rules are not yet final, and therefore the application of those provisions to us is uncertain at this time. The financial reform legislation may also cause our derivatives counterparties to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties.

Risks Relating to Our Business

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

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

• the facilities' performing below expected levels of efficiency;

• breakdown or failures of equipment;

• operational errors by vessel or tug operators;

• operational errors by us or any contracted facility operator;

• labor disputes; and

• weather-related interruptions of operations.

We may not be successful in implementing our proposed business strategy to provide liquefaction capabilities at the Sabine Pass LNG terminal adjacent to the existing regasification facilities.

The Liquefaction Project will require very significant financial resources, which may not be available on terms reasonably acceptable to us or at all. Our SPAs with KOGAS, GAIL and Total contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision to construct Train 3, Train 4 or Train 5, respectively. If these conditions are not met by December 31, 2013 with respect to KOGAS and GAIL and June 30, 2015 with respect to Total, the applicable party may terminate the respective SPA. In addition, if, by June 30, 2013, we have not made a positive final investment decision (i) to construct Train 3, either party may cancel BG's annual contract quantity of 34.0 million MMBtu commencing upon the date of first commercial delivery for Train 3 and the 33.5 million MMBtu commencing upon the date of first commercial delivery for Train 4 and (ii) to construct Train 4, either party may cancel BG's annual contract quantity of 33.5 million MMBtu commencing upon the date of first commercial delivery for Train 4.

It will take several years to construct our proposed liquefaction facilities, and we do not expect Train 1 to produce LNG until the end of 2015, at the earliest. Even if successfully constructed, our proposed liquefaction facilities would be subject to the operating risks described herein. Accordingly, there are many risks associated with the Liquefaction Project, and if we are not

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successful in implementing our business strategy, we may not be able to generate cash flows, which could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Cost overruns and delays in the completion of one or more Trains, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The actual construction costs of the Trains may be significantly higher than our current estimates as a result of many factors, including change orders under existing or future engineering, procurement and construction contracts. We do not have any prior experience in constructing liquefaction facilities, and no liquefaction facilities have been constructed and placed in service in the United States in over 40 years. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both.

Key factors that may affect the timing of, cost of, or our ability to complete, one or more of our proposed Trains 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 our proposed 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 enter into additional satisfactory agreements with contractors and to maintain good relationships with these contractors in order to construct our 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;

• shortages of materials or delays in delivery of materials;

• 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 adjacent to the existing regasification facilities;

• the ability to attract sufficient skilled and unskilled labor, increases in the level of labor costs and the existence of any labor disputes; and

• weather conditions, such as hurricanes.

Delays in the construction of one or more Trains beyond the estimated development periods, as well as change orders to the EPC Contracts with Bechtel or any future engineering, procurement and construction contract related to additional Trains, 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 Liquefaction Project is constructed (which could cause further delays). Our ability to obtain financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factors beyond our control. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Delays in the completion of one or more Trains could lead to reduced revenues or termination of one or more of the SPAs by our counterparties.

Any delay in completion of a Train may prevent us from commencing operations when anticipated, which could 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, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our ability to complete development of additional Trains will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to implement or complete our business plan and our business may ultimately be unsuccessful.

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We will require significant additional funding to be able to commence construction of Train 3 through Train 6, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in development of additional Trains, and we may never be able to complete the development of our business plan. Even if we are able to obtain funding, the funding may be inadequate to cover any increases in costs or delays in completion of the applicable Train, which may 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, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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 Sabine Pass Liquefaction, 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 result in an interruption of our operations, a delay in the completion of the Liquefaction Project, higher construction costs, and the deferral of the dates on which payments are due to Sabine Pass Liquefaction under the SPAs, all of which 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, resulting in the temporary suspension of construction of the Sabine Pass LNG terminal. In September 2008, Hurricane Ike struck the Texas and Louisiana coast, and the Sabine Pass LNG terminal experienced minor 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 and related infrastructure, as well as delays or cost increases in the construction and the development of the Liquefaction Project and related infrastructure. If there are changes in the global climate, storm frequency and intensity may increase; should it result in rising seas, our coastal operations may be impacted.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, 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, including the Liquefaction Project, 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 the FERC has issued an order under the Section 3 of the NGA authorizing the siting, construction and operation of four Trains, the FERC order requires us to obtain certain additional approvals in conjunction with ongoing construction and operations of our proposed liquefaction facilities. Authorizations obtained from other federal and state regulatory agencies also contain ongoing conditions, and additional approval and permit requirements may be imposed. We have no control over the outcome of

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the review and approval process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any existing or potential interventions or other actions by third parties will 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 our projects. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

We are entirely dependent on Cheniere, including employees of Cheniere and its subsidiaries, for key personnel, and a loss of key personnel could have a material adverse effect on our business.

As of February 12, 2013, Cheniere and its subsidiaries had 306 full-time employees, including 163 employees who directly supported the Sabine Pass LNG terminal operations and Liquefaction Project construction. We have contracted with subsidiaries of Cheniere to provide the personnel necessary for the operation, maintenance and management of the Sabine Pass LNG terminal and construction of the Liquefaction Project. We face competition for these highly skilled employees in the immediate vicinity of the Sabine Pass LNG terminal and more generally from the Gulf Coast hydrocarbon processing and construction industries. 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 to attract and retain personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs.

Our general partner's executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and our general partner does 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 have a material adverse effect on our business. In addition, our future success will depend in part on our general partner's ability to engage, and Cheniere's ability to attract and retain, additional qualified personnel.

We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.

We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, Cheniere Investments has entered into a VCRA with Cheniere Marketing, under which Cheniere Marketing will be able to derive economic benefits to the extent it assists Cheniere Investments in commercializing Cheniere Investments' access to capacity at the Sabine Pass LNG terminal through its TURA with Sabine Pass Liquefaction, which has a TUA with Sabine Pass LNG. In addition, Cheniere Marketing has entered into an SPA to purchase, at its option, any excess LNG produced that is not committed to non-affiliate parties, for up to a maximum of 104,000,000 MMBtu per annum produced from Train 1 through Train 4. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand.

We expect that there will be additional agreements or arrangements with Cheniere and its affiliates, including future transportation, interconnection and gas balancing agreements with one or more Cheniere-affiliated natural gas pipelines as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.

We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminates their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.

We are dependent on Bechtel and other contractors for the successful completion of the Liquefaction Project.

Timely and cost-effective completion of the Liquefaction Project in compliance with agreed specifications is central to our business strategy and is highly dependent on Bechtel's and our other contractors' performance under their agreements. Bechtel's and our other contractors' ability to perform successfully under their agreements is dependent on a number of factors, including their ability to:

• design and engineer each Train to operate in accordance with specifications;

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• 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 agreements 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 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. The obligations of Bechtel and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein. 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 applicable liquefaction facility or result in a contractor's unwillingness to perform further work on the Liquefaction 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, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are relying on third-party engineers to estimate the future capacity ratings and performance capabilities of our proposed liquefaction facilities, and these estimates may prove to be inaccurate.

We are relying on third parties, principally Bechtel, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of our proposed liquefaction facilities. If any Train, when actually constructed, fails to have the capacity ratings and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our Trains to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

If third-party pipelines and other facilities interconnected to our pipelines and facilities are or become unavailable to transport natural gas, this could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

We will depend upon third-party pipelines and other facilities that will provide gas delivery options to our Liquefaction Project and to Creole Trail Pipeline. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to meet our SPA obligations could be restricted, thereby reducing our revenues and this could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

We may not be able to purchase or receive physical delivery of sufficient natural gas 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 or receive physical delivery of sufficient quantities of natural gas to satisfy those delivery obligations, which may provide affected SPA customers with the right to terminate their SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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

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The operation of the Sabine Pass LNG terminal, and the construction and operation of the Liquefaction Project, is 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.

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, contracts, financial condition, operating results, cash flow, liquidity and prospects. 

Decreases in the demand for and price of LNG and natural gas could affect the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

The development of domestic LNG facilities and projects generally is based on assumptions about the future availability of natural gas, price of natural gas and LNG, and the prospects for international natural gas and LNG markets. 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 LNG and natural gas, which could adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Cyclical or other changes in the demand for LNG and natural gas 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 our proposed liquefaction facilities;

• 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;

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• 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, to procure customers for LNG or regasified LNG, or to procure natural gas to be liquefied and exported to international markets, at economical prices, or at all.

Failure of imported or exported LNG to be a competitive source of energy could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Current operations at the Sabine Pass LNG terminal are dependent upon the ability of our TUA customers to import LNG supplies into the U.S., which is primarily dependent upon LNG being a competitive source of energy in North America. In North America, due mainly to a historically abundant supply of natural gas and recent discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. The success of the regasification services component of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to North America at a lower cost than the cost to produce some domestic supplies of natural gas, or other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas have recently been and may continue to be discovered in North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than imported LNG.

Operations at our proposed liquefaction facilities will be dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas have recently been and may continue to be discovered outside North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than LNG exported to these markets.

Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG suppliers and merchants in such countries to import or export LNG from or to the United States. Furthermore, some foreign suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to competitors' LNG facilities in the United States. In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy, which can be or become available at a lower cost in certain markets.

As a result of these and other factors, LNG may not be a competitive source of energy in the United States or internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources could adversely affect the ability of our customers to deliver LNG from the United States or to the United States on a commercial basis. Any significant impediment to the ability to deliver LNG to or from the United States generally, or to the Sabine Pass LNG terminal or from our proposed liquefaction facilities specifically, could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Various economic and political factors could negatively affect the development of LNG facilities, including the Liquefaction Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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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, 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 have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, 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 business 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.

We may not be able to secure firm pipeline transportation capacity on economic terms that is sufficient to meet our feed gas transportation requirements which could have a material adverse effect on us.

We believe that there is sufficient capacity on the Creole Trail Pipeline to accommodate all of our natural gas supply requirements for Train 1 and Train 2 but not for additional Trains. We plan to secure additional pipeline transportation capacity but we may not be able to do so on commercially reasonable terms or at all, which would impair our ability to fulfill our obligations under certain of our SPAs and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We face competition based upon the international market price for LNG.

The Liquefaction Project is subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs with respect to Train 5 and Train 6. Should we find it necessary to replace an existing SPA, factors relating to competition may prevent us from entering into a replacement SPA on economically comparable terms, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from the Liquefaction Project are diverse and include, among others:

• increases in worldwide LNG production capacity and availability of LNG for market supply;

• increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;

• increases in the cost to supply natural gas feedstock to the Liquefaction Project;

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• decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;

• increases in capacity and utilization of nuclear power and related facilities; and

• displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.

Terrorist attacks or military campaigns may adversely impact our business.

A terrorist or military incident involving an LNG facility or LNG vessel may result in delays in, or cancellation of, construction of new LNG facilities, including one or more of the Trains, 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 the Sabine Pass LNG terminal, which could increase our costs and decrease our cash flows, depending on the duration of the closure. Our operations 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 business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Existing and future environmental and similar laws and governmental 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 regulate and restrict, among other things, discharges to air, land and water, with particular respect to the protection of the environment; the handling, storage and disposal of hazardous materials, 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 Clean Water Act (the "CWA") and the Resource Conservation and Recovery Act (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 facilities, 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 liabilities, fines and penalties or to capital expenditures related to pollution control equipment that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, 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 our facilities, 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 Environmental Protection Agency (the "EPA"). In addition, as we consume natural 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, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our lack of diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Substantially all of our anticipated revenue in 2013 will be dependent upon one facility, the Sabine Pass LNG receiving terminal located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the

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Sabine Pass LNG terminal, 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.

If we do not make acquisitions or implement capital expansion projects on economically acceptable terms, our future growth and our ability to increase distributions to our unitholders will be limited.

Our ability to grow depends on our ability to make accretive acquisitions or implement accretive capital expansion projects, such as the Liquefaction Project. We may be unable to make accretive acquisitions or implement accretive capital expansion projects for any of the following reasons:

• we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

• we are unable to identify attractive capital expansion projects or negotiate acceptable engineering procurement and construction arrangements for them;

• we are unable to obtain necessary governmental approvals;

• we are unable to obtain financing for the acquisitions or capital expansion projects on economically acceptable terms, or at all;

• we are unable to secure adequate customer commitments to use the acquired or expansion facilities; or

• we are outbid by competitors.

If we are unable to make accretive acquisitions or implement accretive capital expansion projects, then our future growth and ability to increase distributions to our unitholders will be limited.

We intend to pursue acquisitions of additional LNG terminals, natural gas pipelines and related assets in the future, either directly from Cheniere or from third parties. However, Cheniere is not obligated to offer us any of these assets other than, in certain circumstances under an investors rights agreement with Blackstone CQP Holdco LP, its proposed Corpus Christi liquefaction project. If Cheniere does offer us the opportunity to purchase assets, we may not be able to successfully negotiate a purchase and sale agreement and related agreements, we may not be able to obtain any required financing for such purchase and we may not be

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able to obtain any required governmental and third-party consents. The decision whether or not to accept such offer, and to negotiate the terms of such offer, will be made by the conflicts committee of our general partner, which may decline the opportunity to accept such offer for a variety of reasons, including a determination that the acquisition of the assets at the proposed purchase price would not result in an increase, or a sufficient increase, in our adjusted operating surplus per unit within an appropriate timeframe.

If we make acquisitions, they could adversely affect our business and ability to make distributions to our unitholders.

If we make any acquisitions, they will involve potential risks, including:

• an inability to integrate successfully the businesses that we acquire with our existing business;

• a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the acquisition;

• the assumption of unknown liabilities;

• limitations on rights to indemnity from the seller;

• mistaken assumptions about the cash generated, or to be generated, by the business acquired or the overall costs of equity or debt;

• the diversion of management's and employees' attention from other business concerns; and

• unforeseen difficulties encountered in operating new business segments or in new geographic areas.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our future funds and other resources. In addition, if we issue additional units in connection with future growth, our existing unitholders' interest in us will be diluted, and distributions to our unitholders may be reduced. 

Risks Relating to Our Cash Distributions

The issuance of additional common units will increase the risk that we will be unable to make the initial quarterly distribution on our common units.

We are currently paying the initial quarterly distribution of $0.425 on each of our common units and the related distribution on the general partner units. We are currently not paying any distributions on the subordinated units. The Class B units are not entitled to receive distributions until they convert into common units. As of December 31, 2012, we had 39,488,488 common units outstanding. The aggregate initial minimum quarterly distribution on these common units and the related general partner units is $68.5 million per year. We are not currently generating sufficient operating surplus each quarter to pay the initial quarterly distribution on all of these units and therefore intend to use a portion of our accumulated operating surplus each quarter to enable us to make this distribution. We may not have sufficient operating surplus to continue paying the initial quarterly distribution on all of our common units before Train 1 and Train 2 commence commercial operations, which is not expected to occur until at least 2016. Furthermore, if Train 1 and Train 2 do not commence commercial operations as expected and the outstanding Class B units convert into common units, we may not have sufficient operating surplus to be able to pay the initial quarterly distribution on all common units then outstanding.

Accordingly, until Train 1 and Train 2 commence commercial operations, the amount of cash that we can distribute on our common units principally will depend upon the amount of cash that we generate from our existing operations, which will be based on, among other things:

• performance by counterparties of their obligations under the TUAs;

• performance by Sabine Pass LNG of its obligations under the TUAs;

• performance by, and the level of cash receipts received from, Cheniere Marketing under the VCRA; and

• the level of our operating costs, including payments to our general partner and its affiliates.

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In addition, the actual amount of cash that we will have available for distribution will depend on other factors such as:

• the restrictions contained in our debt agreements and our debt service requirements, including the ability of Sabine Pass LNG to pay distributions to us under the indentures governing the Sabine Pass LNG Senior Notes as a result of requirements for a debt service reserve account, a debt payment account and satisfaction of a fixed charge coverage ratio and the ability of Sabine Pass Liquefaction to pay distributions to us under its credit facility and the Sabine Liquefaction Notes;

• the costs and capital requirements of acquisitions, if any;

• fluctuations in our working capital needs;

• our ability to borrow for working capital or other purposes; and

• the amount, if any, of cash reserves established by our general partner.

We may not be successful in our efforts to maintain or increase our cash available for distribution to cover the initial quarterly distribution on our common units. Any reductions in distributions to our unitholders because of a shortfall in cash flow or other events will result in a decrease of the quarterly distribution on our common units below the initial quarterly distribution. Any portion of the initial quarterly distribution that is not distributed on our common units will accrue and be paid to the common unitholders in accordance with our partnership agreement, if at all.

We will need to refinance, extend or otherwise satisfy our substantial indebtedness, and principal amortization or other terms of our future indebtedness could limit our ability to pay or increase distributions to our unitholders.

We are not generally required to make principal payments on any of our senior notes prior to maturity. Our ability to refinance, extend or otherwise satisfy our indebtedness, and the principal amortization, interest rate and other terms on which we may be able to do so, will depend among other things on our then contracted or otherwise anticipated future cash flows available for debt service. Our TUAs with Total and Chevron, which provide substantially all of our current operating cash flows, will expire in 2029 unless extended. Our ability to pay or increase distributions to our unitholders in future years could be limited by principal amortization, interest rate or other terms of our future indebtedness.

Our subsidiaries may be restricted under the terms of their indebtedness from making distributions to us under certain circumstances, which may limit our ability to pay or increase distributions to our unitholders and could materially and adversely affect the market price of our common units.

The agreements governing our indebtedness restricts payments that our subsidiaries can make to us in certain events and limits the indebtedness that our subsidiaries can incur. For example, Sabine Pass LNG may not make distributions until, among other requirements, a deposit has been made in an interest payment account for one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, a deposit has been made to a permanent debt service reserve fund for one semi-annual interest payment and a fixed charge coverage ratio test of 2:1 is satisfied. Sabine Pass Liquefaction is likewise restricted from making distributions under agreements governing its indebtedness until, among other requirements, substantial completion of Train 1 and Train 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio of 1.25:1.00 is satisfied. Our subsidiaries' inability to pay distributions to us or to incur additional indebtedness as a result of the foregoing restrictions in the agreements governing their indebtedness may inhibit our ability to pay or increase distributions to our unitholders.

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 indentures governing the Sabine Pass LNG Notes (the "Sabine Pass Indentures"). In order to satisfy this fixed charge coverage ratio test, we estimate that Sabine Pass LNG's consolidated cash flow, as defined in such indentures, must be greater than approximately $340 million. Thus, TUA payments from Sabine Pass Liquefaction and either Chevron or Total are needed to satisfy the test. If the fixed charge coverage ratio test is not satisfied, Sabine Pass LNG will not be permitted by the Sabine Pass Indentures 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, financial condition, operating results, liquidity and prospects.

Restrictions in agreements governing our subsidiaries' indebtedness may prevent our subsidiaries from engaging in certain beneficial transactions.

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In addition to restrictions on the ability of Sabine Pass LNG and Sabine Pass Liquefaction to make distributions or incur additional indebtedness, the agreements governing their indebtedness also contain various other covenants that may prevent them from engaging in beneficial transactions, including limitations on their ability 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.

Management fees and cost reimbursements due to our general partner and its affiliates will reduce cash available to pay distributions to our unitholders.

We pay significant management fees to our general partner and its affiliates and reimburse them for expenses incurred on our behalf, which reduces our cash available for distribution to our unitholders. See Note 13—"Related Party Transactions" in our Notes to Consolidated Financial Statements for a description of these fees and expenses. Our general partner and its affiliates will also be entitled to reimbursement for all other direct expenses that they incur on our behalf. The payment of fees to our general partner and its affiliates and the reimbursement of expenses could adversely affect our ability to pay cash distributions to our unitholders.

The amount of cash that we have available for distributions to our unitholders will depend primarily on our cash flow and not solely on profitability.

The amount of cash that we will have available for distributions will depend primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.

As a result of the assignment of the Cheniere Marketing TUA to Cheniere Investments in June 2010, our available cash for distributions was reduced. Therefore, we have not paid any distributions on our subordinated units with respect to the quarters ended on or after June 30, 2010.  We may not have sufficient cash available for distributions on our subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact our ability to pay the initial quarterly distribution on our common units in full or at all.

We may not be able to maintain or increase the distributions on our common units unless we are able to make accretive acquisitions or implement accretive capital expansion projects, which may require us to obtain one or more sources of funding.

We may not be able to make accretive acquisitions or implement accretive capital expansion projects, including our proposed liquefaction facilities, that would result in sufficient cash flow to fully pay distributions to the subordinated unitholders and allow us to increase common unitholder distributions. To fund acquisitions or capital expansion projects, we will need to pursue a variety of sources of funding, including debt and/or equity financings. Our ability to obtain these or other types of financing will depend, in part, on factors beyond our control, such as our ability to obtain commitments from users of the facilities to be acquired or constructed, the status of various debt and equity markets at the time financing is sought and such markets' view of our industry and prospects at such time. Any restrictive lending conditions in the U.S. credit markets may make it more time consuming and expensive for us to obtain financing, if we can obtain such financing at all. Accordingly, we may not be able to obtain financing for acquisitions or capital expansion projects on terms that are acceptable to us, if at all.

Risks Relating to an Investment in Us and Our Common Units

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Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of us and our unitholders.

Cheniere controls our general partner, which has sole responsibility for conducting our business and managing our operations. Some of our general partner's directors are also directors of Cheniere, and certain of our general partner's officers are officers of Cheniere. Therefore, conflicts of interest may arise between Cheniere and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of us and our unitholders. These conflicts include, among others, the following situations:

• neither our partnership agreement nor any other agreement requires Cheniere to pursue a business strategy that favors us. Cheniere's directors and officers have a fiduciary duty to make these decisions in favor of the owners of Cheniere, which may be contrary to our interests:

• our general partner controls the interpretation and enforcement of contractual obligations between us, on the one hand, and Cheniere, on the other hand, including provisions governing administrative services and acquisitions;

• our general partner is allowed to take into account the interests of parties other than us, such as Cheniere and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us and our unitholders;

• our general partner has limited its liability and reduced its fiduciary duties under the partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty;

• Cheniere is not limited in its ability to compete with us. Please read "-Cheniere is not restricted from competing with us and is free to develop, operate and dispose of, and is currently developing, LNG terminals, pipelines and other assets without any obligation to offer us the opportunity to develop or acquire those assets";

• our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities, and the establishment, increase or decrease in the amounts of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

• our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

• our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;

• our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

• our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; and

• our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

We expect that there will be additional agreements or arrangements with Cheniere and its affiliates, including future interconnection, natural gas balancing and storage agreements with one or more Cheniere-affiliated natural gas pipelines, services agreements, as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.

Cheniere is not restricted from competing with us and is free to develop, operate and dispose of, and is currently developing, LNG terminals, pipelines and other assets without any obligation to offer us the opportunity to develop or acquire those assets.

Cheniere and its affiliates are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. Cheniere may acquire, construct or dispose of its proposed Corpus Christi or Creole Trail LNG terminals, its proposed pipelines or any other assets without any obligation to offer us the opportunity to purchase or construct any of those assets. In

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addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to Cheniere and its affiliates. As a result, neither Cheniere nor any of its affiliates will have any obligation to present new business opportunities to us, and they may take advantage of such opportunities themselves. Cheniere also has significantly greater resources and experience than we have, which may make it more difficult for us to compete with Cheniere and its affiliates with respect to commercial activities or acquisition candidates.

Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

• permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

• provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner, as long as it acted in good faith, meaning that it believed the decision was in the best interests of our partnership;

• generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us;

• provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was criminal; and

• provides that in resolving conflicts of interest, it will be presumed that in making its decision the conflicts committee or the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen entirely by Cheniere Subsidiary Holdings, LLC ("Cheniere Subsidiary Holdings"), an affiliate of Cheniere. As a result, the price at which the common units will trade could be diminished because of the absence or reduction of a control premium in the trading price.

Even if unitholders are dissatisfied, they cannot initially remove our general partner without its consent.

Our unitholders are unable to remove our general partner without the consent of affiliates of Cheniere because those affiliates own a sufficient number of common, Class B and subordinated units to be able to prevent removal of our general partner. The vote of the holders of at least 66 2/3% of all outstanding common, Class B and subordinated units (including any units owned by

27

our general partner and its affiliates) voting together as a single class is required to remove our general partner. Affiliates of Cheniere own approximately 59% of our outstanding common, Class B and subordinated units. In addition, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of poor management of the business, so the removal of the general partner because of the unitholder's dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.

Our partnership agreement restricts the voting rights of unitholders (other than our general partner and its affiliates) owning 20% or more of any class of our units.

Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Our partnership agreement prohibits a unitholder (other than our general partner and its affiliates) who acquires 15% or more of our limited partner units without the approval of our general partner from engaging in a business combination with us for three years unless certain approvals are obtained. This provision could discourage a change of control that our unitholders may favor, which could negatively affect the price of our common units.

Our partnership agreement effectively adopts Section 203 of the Delaware General Corporation Law ("DGCL"). Section 203 of the DGCL as it applies to us prevents an interested unitholder-defined as a person (other than our general partner and its affiliates) who owns 15% or more of our outstanding limited partner units-from engaging in business combinations with us for three years following the time such person becomes an interested unitholder unless certain approvals are obtained. Section 203 broadly defines "business combination" to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. This provision of our partnership agreement could have an anti-takeover effect with respect to transactions not approved in advance by our general partner, including discouraging takeover attempts that might result in a premium over the market price for our common units.

Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for contractual obligations of the partnership that are expressly made without recourse to the general partner. We are organized under Delaware law, and we conduct business in other states. As a limited partner in a partnership organized under Delaware law, holders of our common units could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the "control" of

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our business. In addition, limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions.

Our unitholders may have liability to repay distributions wrongfully made.

Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that, for a period of three years from the date of the impermissible distribution, partners who received such a distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partner interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

We may issue additional units without approval of our unitholders, which would dilute their ownership interest.

At any time during the subordination period, with the approval of the conflicts committee of the board of directors of our general partner, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. After the subordination period, we may issue an unlimited number of limited partner interests of any type without limitation of any kind. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our unitholders' proportionate ownership interest in us will decrease;

• the amount of cash available per unit to pay distributions may decrease;

• because a lower percentage of total outstanding units will be subordinated units, the risk will increase that a shortfall in the payment of the initial quarterly distributions will be borne by our common unitholders;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

The price of our common units may fluctuate significantly, and our unitholders could lose all or part of their investment.

The market price of our common units may be influenced by many factors, some of which are beyond our control, including:

• our quarterly distributions;

• our quarterly or annual earnings or those of other companies in our industry;

• actual or potential non-performance by any customer or a counterparty under any agreement;

• announcements by us or our competitors of significant contracts;

• changes in accounting standards, policies, guidance, interpretations or principles;

• general economic conditions;

• the failure of securities analysts to cover our common units or changes in financial or other estimates by analysts;

• future sales of our common units; and

• other factors described in these "Risk Factors."

Affiliates of our general partner may sell limited partner units, which sales could have an adverse impact on the trading price of the common units.

Sales by us or any of our affiliated unitholders of a substantial number of our common units or our subordinated units, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. Affiliates of Cheniere own 11,963,488 common units, 135,383,831 subordinated units and 33,333,334 Class B units. All of the subordinated units will convert into common units at the

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end of the subordination period and may convert earlier. Any sales of these units could have an adverse impact on the price of the common units.

Risks Relating to Tax Matters

Our tax treatment depends on our status as a partnership for federal income tax purposes. If we were treated as a corporation for federal income tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service ("IRS") on this matter.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distributions to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to you.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively.  We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.  Any such changes could negatively impact the value of an investment in our common units and the amount of cash available for distribution to our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.

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We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular unit is transferred.  The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A change in tax treatment of our partnership, or a successful IRS contest of the federal income tax positions that we take, may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.

The IRS may adopt positions that differ from the positions that we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions that we take. A court may not agree with some or all of the positions that we take. Any contest with the IRS may adversely impact the taxable income reported to our unitholders and the income taxes they are required to pay. As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. 

Our unitholders may be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in amount from the cash that we distribute, our unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability which results from their share of our taxable income.

We intend to allocate items of income, gain, loss and deduction among the holders of our common units and subordinated units on or after the date that the subordination period ends to ensure that common units issued in exchange for our subordinated units have the same economic and federal income tax characteristics as our other common units. Any such allocation of items of our income or gain to unitholders, which may include allocations to holders of our common units, would not be accompanied by a distribution of cash to such unitholders. In addition, any such allocation of items of deduction or loss to specific unitholders (for example, to the holder of the subordinated units) would effectively reduce the amount of items of deduction or loss that will be allocated to other unitholders.

Tax gain or loss on the disposition of our common units could be different than expected.

If our unitholders sell common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of the unitholders' allocable share of our net taxable income decrease the unitholders' tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, even if the price received is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income due to the potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder's share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investments in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them.

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Non-U.S. investors face unique tax issues from owning common units that may result in adverse tax consequences to them.

Non-U.S. investors who own common units will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Distributions to non-U.S. investors will generally be reduced by withholding taxes at the highest applicable effective tax rate (currently 35%) whether or not we have taxable income. The IRS has taken the position that a non-U.S. investor's gain on the sale of common units is subject to United States federal income tax.

We will treat each holder of our common units as having the same tax benefits without regard to the actual common units held. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of applicable Treasury Regulations.

The IRS may challenge the manner in which we calculate our unitholder's basis adjustment under Section 743(b) of the Internal Revenue Code. If so, because neither we nor the unitholder can identify the units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all unitholders selling units within the period under audit as if all unitholders owned such units.

Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders.

Our unitholders will likely be subject to state and local taxes and return filing requirements as a result of an investment in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the unitholder does not live in any of those jurisdictions. Our unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Furthermore, our unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own property or conduct business in additional states or foreign countries that impose a personal tax or an entity level tax. Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of our unitholders to file all United States federal, state and local tax returns.

The sale or exchange of 50% or more of the total interest in our capital and profits during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if special relief from the IRS was not available) for one fiscal year. Our technical termination could also result in a deferral of depreciation deductions allowable in computing our taxable income.

In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in the unitholder's taxable income for the year of termination. Our technical termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership, we would be required to make new tax elections and we could be subject to penalties if we are unable to determine that a technical termination occurred.

We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders.  The IRS may challenge this treatment, which could adversely affect the value of the common units.

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When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our common units as a means to measure fair market value of our assets. Our methodology may be viewed as understating the value of our assets.  In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders.  Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets.  The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders.  It also could affect the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

A unitholder whose common units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.  Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.  Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

 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, 2012, 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 UNITHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES

Our common units began trading on the NYSE MKT under the symbol "CQP" commencing with our initial public offering on March 21, 2007. The table below presents the high and low daily closing sales prices per common unit, as reported by the NYSE MKT, and cash distributions to common unitholders for the period indicated.

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	High		Low		Cash Distributions Per Common Unit (1)		Cash Distributions Per Subordinated Unit (2)
Three Months Ended
March 31, 2012	$	24.70	$	18.05	$	0.425	$	—
June 30, 2012	27.14		19.81		0.425		—
September 30, 2012	26.58		22.67		0.425		—
December 31, 2012	23.22		17.87		0.425		—
Three Months Ended
March 31, 2011	24.29		15.31		0.425		—
June 30, 2011	19.32		16.37		0.425		—
September 30, 2011	19.46		12.07		0.425		—
December 31, 2011	18.35		12.40		0.425		—

(1) We also paid cash distributions to our general partner with respect to its 2% general partner interest.

(2) As a result of the assignment of Cheniere Marketing's TUA to Cheniere Investments, effective July 1, 2010, our available cash for distributions was reduced. Therefore, we did not pay any distributions on our subordinated units with respect to the quarters ended on or after June 30, 2010.

(3) In 2012, we issued Class B units, a new class of equity interests representing limited partner interests in us, in connection with the development of the Liquefaction Project. The Class B units are not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale of substantially all of our assets). The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basis beginning on the initial purchase of the Class B units, and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The holders of Class B units have a preference over the holders of the subordinated units in the event of a liquidation (or merger, combination or sale of substantially all of our assets).

A distribution for the quarter ended December 31, 2012 of $0.425 per common unit was paid on February 14, 2013. In addition, we paid cash distributions to our general partner with respect to its 2% general partner interest.

As of February 13, 2013, we had (i) 39,488,488 common units outstanding held by approximately 9 record owners and (ii) 133,333,334 Class B units outstanding, of which 100,000,000 Class B units were held by Blackstone CQP Holdco LP and 33,333,334 Class B units were held by a wholly owned subsidiary of Cheniere.

We consider cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. The Sabine Pass Indentures described in "Management’s Discussion and Analysis of Financial Condition and Results of Operations" may prohibit Sabine Pass LNG from making cash distributions to us under certain circumstances, which could limit our ability to make distributions.

Upon the closing of our initial public offering, Cheniere received 135,383,831 subordinated units. Below is a description of our cash distribution policy regarding common and subordinated units. References therein to "unitholders" made in the context of the recipients of quarterly cash distributions refer to our common unitholders and subordinated unitholders.

Cash Distribution Policy

Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.

Subordination Period

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During the subordination period, the common units will 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. Cheniere Subsidiary Holdings, LLC owns all of the 135,383,831 subordinated units, representing 43.9% of the limited partner interests in us as of December 31, 2012. 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 distribution on the common units.

As a result of the assignment of Cheniere Marketing's TUA to Cheniere Investments, effective July 1, 2010, our available cash for distributions was reduced. Therefore, we have not paid distributions on our subordinated units since the distribution made with respect to the quarter ended March 31, 2010.

Definition of Subordination Period

The subordination period will extend until the first business day following the distribution of available cash to partners in respect of any quarter that each of the following occurs: 

• distributions of available cash from operating surplus on each of the outstanding common units (assuming conversion of the Class B units), subordinated units and any other outstanding units that are senior or equal in right of distribution to the subordinated units equaled or exceeded the initial quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

• the "adjusted operating surplus" (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the initial quarterly distributions on all of the outstanding common units (assuming conversion of the Class B units), subordinated units, general partner units and any other outstanding units that are senior or equal in right of distribution to the subordinated units during those periods on a fully diluted basis; and

• there are no arrearages in payment of the initial quarterly distribution on the common units.

Expiration of the Subordination Period

When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:  

• the subordination period will end and each subordinated unit will immediately convert into one common unit;

• any existing arrearages in payment of the initial quarterly distribution on the common units will be extinguished; and

• the general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Early Conversion of Subordinated Units

The subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis on the first business day following the distribution of available cash to partners in respect of any quarter that each of the following occurs: 

• in connection with distributions of available cash from operating surplus, the amount of such distributions constituting "contracted adjusted operating surplus" (as defined below) on each outstanding common unit (assuming conversion of the Class B units), subordinated unit and any other outstanding unit that is senior or equal in right of distribution to the subordinated units equaled or exceeded $0.638 (150% of the initial quarterly distribution) for each quarter in the four-quarter period immediately preceding that date;

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• the contracted adjusted operating surplus generated during each quarter in the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $0.638 (150% of the initial quarterly distribution) on all of the outstanding common units (assuming conversion of the Class B units), subordinated units, general partner units, any other units that are senior or equal in right of distribution to the subordinated units, and any other equity securities that are junior to the subordinated units that the board of directors of our general partner deems to be appropriate for the calculation, after consultation with management of our general partner, on a fully diluted basis; and

• there are no arrearages in payment of the initial quarterly distribution on the common unitsd

Definition of Adjusted Operating Surplus

We define adjusted operating surplus in our partnership agreement, and for any period, it generally means: 

• operating surplus generated with respect to that period; less

• any net increase in working capital borrowings with respect to that period; less

• any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

• any net decrease in working capital borrowings with respect to that period; plus

• any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes the $30 million operating surplus "basket," net increases in working capital borrowings, net drawdowns of reserves of cash generated in prior periods.

Definition of Contracted Adjusted Operating Surplus

We define contracted adjusted operating surplus in our partnership agreement and it:

• generally means adjusted operating surplus derived solely from SPAs and TUAs, in each case, with a minimum term of three years with counterparties who are not affiliates of Cheniere; and

• excludes revenues and expenses attributable to the portion of payments made under the LNG sale and purchase agreements related to the final settlement price for the New York Mercantile Exchange's Henry Hub natural gas futures contract for the month in which the relevant cargo's delivery window is scheduled. 

Class B Units

In 2012, we issued Class B units, a new class of equity interests representing limited partner interests in us, in connection with the development of the Liquefaction Project. The Class B units are not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale of substantially all of our assets). The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basis beginning on the initial purchase of the Class B units, and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The holders of Class B units have a preference over the holders of the subordinated units in the event of a liquidation (or merger, combination or sale of substantially all of our assets).

General Partner Units and Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus in excess of the initial quarterly distribution. Our general partner currently holds the incentive distribution rights but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

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Assuming we do not issue any additional classes of units and our general partner maintains its 2% interest, if we have made distributions to our unitholders from operating surplus in an amount equal to the initial quarterly distribution for any quarter, assuming no arrearages, then we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner as follows:

	Total Quarterly Distribution Target Amount	Marginal Percentage Interest Distributions
		Common and Subordinated Unitholders	General Partner
Initial quarterly distribution	$0.425	98%	2%
First Target Distribution	Above $0.425 up to $0.489	98%	2%
Second Target Distribution	Above $0.489 up to $0.531	85%	15%
Third Target Distribution	Above $0.531 up to $0.638	75%	25%
Thereafter	Above $0.638	50%	50%

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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,
	2012			2011			2010			2009			2008
	(in thousands)
Statement of Operations Data:
Revenues (including transactions with affiliates)	$	264,327		$	283,790		$	399,282		$	416,790		$	15,000
Expenses (including transactions with affiliates)	200,787			139,164			118,485			88,870			32,141
Income (loss) from operations	63,540			144,626			280,797			327,920			(17,141		)
Other expense	(213,676		)	(175,645		)	(173,229		)	(141,008		)	(61,203		)
Net income (loss)	(150,136		)	(31,019		)	107,568			186,912			(78,344		)
Cash Flow Data:
Cash flows provided by (used in) operating activities	(26,214		)	14,249			104,137			234,311			(1,156		)
Cash flows provided by (used in) investing activities	(4,455		)	(8,191		)	(5,076		)	92,146			(560		)
Cash flows provided by (used in) financing activities	368,546			22,008			(163,254		)	(208,922		)	1,710

	December 31,
	2012		2011		2010		2009		2008
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	419,292	$	81,415	$	53,349	$	117,542	$	7
Restricted cash and cash equivalents (current)	92,519		13,732		13,732		13,732		235,985
Non-current restricted cash and cash equivalents	272,425		82,394		82,394		82,394		137,984
Non-current restricted U.S. Treasury securities	—		—		—		—		20,829
Property, plant and equipment, net	2,704,895		1,514,416		1,550,465		1,588,557		1,517,507
Total assets	3,748,278		1,737,300		1,743,492		1,859,473		1,978,835
Long-term debt, net of discount	2,167,113		2,192,418		2,187,724		2,110,101		2,107,673
Long-term debt—related party, net of discount	—		—		—		72,928		70,661
Long-term debt—affiliate	—		—		—		—		2,372
Deferred revenue	21,500		25,500		29,500		33,500		37,500
Deferred revenue—affiliate	14,720		12,266		9,813		7,360		4,971

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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 

• Summary of Critical Accounting Policies and Estimates

• Recent Accounting Standards

Overview of Business

We are a Delaware limited partnership formed by Cheniere Energy, Inc. ("Cheniere"). Through our wholly owned subsidiary, Sabine Pass LNG, L.P. ("Sabine Pass LNG") we own and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels of up to 265,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Approximately one-half of the receiving capacity at the Sabine Pass LNG terminal is contracted to two multinational energy companies. We are developing natural gas liquefaction facilities (the "Liquefaction Project") at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"). We plan to construct up to six Trains (each in sequence, "Train 1", "Train 2", "Train 3", "Train 4", "Train 5" and "Train 6"), which are in various stages of development. Each Train has a nominal production capacity of approximately 4.5 mmtpa.

Overview of Significant Events

In 2012, and through the filing date of this Form 10-K, we continue to execute our strategy to operate the Sabine Pass LNG terminal, generate steady and reliable revenues under Sabine Pass LNG's long-term terminal use agreements ("TUAs") and develop and construct the Liquefaction Project.

Our significant accomplishments since January 1, 2012 and through the filing date of this Form 10-K, include the following:  

• Sabine Pass Liquefaction entered into three LNG sale and purchase agreements ("SPAs"): (i) an amended and restated SPA with BG Gulf Coast LNG, LLC ("BG"), a subsidiary of BG Group plc, (ii) an SPA with Korea Gas Corporation ("KOGAS") and (iii) an SPA with Total Gas & Power North America, Inc. ("Total"), under which each customer has agreed to purchase LNG in the amount and upon the commencement of operations as designated in the SPAs;

• Sabine Pass Liquefaction and Sabine Pass LNG received authorization from the Federal Energy Regulatory Commission ("FERC") to site, construct and operate facilities for the liquefaction and export of domestically produced natural gas at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. The FERC order authorizes the development of up to four modular Trains;

• We entered into Unit Purchase Agreements (the "Agreements") with Blackstone CQP Holdco LP ("Blackstone") and a wholly owned subsidiary of Cheniere. Under the Agreements, we sold 100.0 million and 33.3 million Class B units to Blackstone and Cheniere, respectively, in the aggregate at a price of $15.00 per Class B unit, for a total investment of

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$2.0 billion. Proceeds from the private placements have been used to fund part of the equity portion of the costs of developing, constructing and placing into service the Liquefaction Project;

• Sabine Pass Liquefaction closed on a $3.6 billion senior secured credit facility (the "Liquefaction Credit Facility") that will be used to fund a portion of the costs of developing, constructing and placing into service Train 1 and Train 2 of the Liquefaction Project;

• We issued a full notice to proceed ("NTP") to Bechtel to construct Train 1 and Train 2 of the Liquefaction Project;

• Sabine Pass LNG repurchased its $550.0 million 7.25% Senior Secured Notes due 2013 (the "2013 Notes") by issuing $420.0 million of 6.50% Senior Secured Notes due in 2020 (the "2020 Notes") and by our selling 8.0 million common units in an underwritten public offering at a price of $25.07 per common unit for net cash proceeds of $194.0 million;

• Sabine Pass Liquefaction and Bechtel entered into a lump sum turnkey contract for the engineering, procurement and construction of Train 3 and Train 4 (the "EPC Contract (Train 3 and 4)"); and

• In February 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $1.5 billion of 5.625% Senior Secured Notes due 2021 (the "Sabine Liquefaction Notes"). Net proceeds from the offering are intended to be used to pay capital costs incurred in connection with the construction of Train 1 and Train 2 of the Liquefaction Project in lieu of a portion of the commitments under the Liquefaction Credit Facility.

Liquidity and Capital Resources

Cash and Cash Equivalents

As of December 31, 2012, we had $419.3 million of cash and cash equivalents and $364.9 million of restricted cash and cash equivalents.

Sabine Pass LNG Terminal

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity of approximately 16.9 Bcfe. 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 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.

The remaining approximately 2.0 Bcf/d of capacity has been reserved under a TUA by Sabine Pass Liquefaction. Sabine Pass Liquefaction is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year, continuing until at least 20 years after Sabine Pass Liquefaction delivers its first commercial cargo at Sabine Pass Liquefaction's facilities under construction, which may occur as early as late 2015. Sabine Pass Liquefaction obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Energy Investments, LLC ("Cheniere Investments"), a wholly owned subsidiary of Cheniere Partners, of its rights, title and interest under its TUA. In connection with the assignment, Sabine Pass Liquefaction, Cheniere Investments and Sabine Pass LNG entered into a terminal use rights assignment and agreement ("TURA") pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to Sabine Pass LNG. In an effort to monetize Cheniere Investments’ reserved capacity under its TURA during construction of the Liquefaction Project, Cheniere Marketing, LLC ("Cheniere Marketing"), a wholly owned subsidiary of Cheniere, has entered into a variable capacity rights agreement ("VCRA") pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross

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margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. The revenue earned by Sabine Pass LNG from the capacity payments made under the TUA and the revenue earned by Cheniere Investments under the VCRA are eliminated upon consolidation of our financial statements. We have guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA.

In September 2012, Sabine Pass Liquefaction entered into a partial TUA assignment agreement with Total, whereby Sabine Pass Liquefaction will progressively gain access to Total's capacity and other services provided under Total's TUA with Sabine Pass LNG.  This agreement will provide Sabine Pass Liquefaction with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Train 5 and Train 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of Train 3, and permit Sabine Pass Liquefaction to more flexibly manage its LNG storage capacity with the commencement of Train 1. Notwithstanding any arrangements between Total and Sabine Pass Liquefaction, payments required to be made by Total to Sabine Pass LNG shall continue to be made by Total to Sabine Pass LNG in accordance with its TUA.

Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered to the Sabine Pass LNG terminal.

Liquefaction Facilities

The Liquefaction Project is being developed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We plan to construct up to six Trains, which are in various stages of development. We have commenced construction of Train 1 and Train 2 and the related new facilities needed to treat, liquefy, store and export natural gas. Construction of Train 3 and Train 4 and the related facilities is expected to commence upon, among other things, obtaining financing commitments sufficient to fund construction of such Trains and making a positive final investment decision. We recently began the development of Train 5 and Train 6 and expect to commence the regulatory approval process in the first half of 2013.

The Trains are being designed, constructed and commissioned by Bechtel using the ConocoPhillips Optimized Cascade® technology, a proven technology deployed in numerous LNG projects around the world. Sabine Pass Liquefaction has entered into lump sum turnkey contracts for the engineering, procurement and construction of Train 1 and Train 2 (the "EPC Contract (Train 1 and 2)") and Train 3 and Train 4 (the "EPC Contract (Train 3 and 4)", and together with the EPC Contract (Train 1 and 2), the "EPC Contracts"), with Bechtel in November 2011 and December 2012, respectively.

In August 2012, we received a final order from the U.S. Department of Energy ("DOE") to export 16 mmtpa of LNG to all nations with which trade is permitted.  In April 2012, we received authorization from the Federal Energy Regulatory Commissin ("FERC") to site, construct and operate Train 1, Train 2, Train 3 and Train 4.

As of December 31, 2012, the overall project completion for Train 1 and Train 2 was approximately 18% complete. Based on our current construction schedule, we anticipate that Train 1 will produce LNG as early as the end of 2015.

Customers

As of February 13, 2013, Sabine Pass Liquefaction has entered into the following third-party SPAs:

• BG Gulf Coast LNG, LLC ("BG") SPA commences upon the date of first commercial delivery for Train 1 and includes an annual contract quantity of 182,500,000 MMBtu of LNG and a fixed fee of $2.25 per MMBtu and includes additional annual contract quantities of 36,500,000 MMBtu, 34,000,000 MMBtu, and 33,500,000 MMBtu upon the date of first commercial delivery for Train 2, Train 3 and Train 4, respectively, with a fixed fee of $3.00 per MMBtu. The total expected annual contracted cash flow from BG from the fixed fee component is $723 million. In addition, Sabine Pass Liquefaction has agreed to make LNG available to BG to the extent that Train 1 becomes commercially operable prior to the beginning of the first delivery window. The obligations of BG are guaranteed by BG Energy Holdings Limited, a company organized under the laws of England and Wales, with a credit rating of A2/A.

• Gas Natural Aprovisionamientos SDG S.A. ("Gas Natural Fenosa"), an affiliate of Gas Natural SDG, S.A., SPA commences upon the date of first commercial delivery for Train 2 and includes an annual contract quantity of 182,500,000 MMBtu of LNG and a fixed fee of $2.49 per MMBtu, equating to expected annual contracted cash flow from the fixed fee component of $454 million. The obligations of Gas Natural Fenosa are guaranteed by Gas Natural SDG S.A., a company organized under the laws of Spain, with a credit rating of Baa2/BBB.

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• Korea Gas Corporation ("KOGAS") SPA commences upon the date of first commercial delivery for Train 3 and includes an annual contract quantity of 182,500,000 MMBtu of LNG and a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of $548 million. KOGAS is organized under the laws of the Republic of Korea, with a credit rating of A/A1.

• GAIL (India) Limited ("GAIL") SPA commences upon the date of first commercial delivery for Train 4 and includes an annual contract quantity of 182,500,000 MMBtu of LNG and a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of $548 million. GAIL is organized under the laws of India, with a credit rating of Baa2/BBB-.

• Total, an affiliate of Total S.A., SPA commences upon the date of first commercial delivery for Train 5 and includes an annual contract quantity of 104,750,000 MMBtu of LNG and a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of $314 million. The obligations of Total are guaranteed by Total S.A., a company organized under the laws of France, with a credit rating of Aa1/AA.

In aggregate, the fixed fee portion to be paid by these customers is approximately $2.6 billion annually, with fixed fees starting from the commencement of operations of Train 1, Train 2, Train 3, Train 4 and Train 5 equating to $411 million, $564 million, $650 million, $648 million and $314 million, respectively.

In addition, Cheniere Marketing has entered into an SPA to purchase, at its option, any excess LNG produced that is not committed to non-affiliate parties, for up to a maximum of 104,000,000 MMBtu per annum produced from Train 1 through Train 4. Cheniere Marketing may purchase incremental LNG volumes at a price of 115% of Henry Hub plus up to $3.00 per MMBtu for the first 36,000,000 MMBtu of the most profitable cargoes sold each year by Cheniere Marketing, and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing.

Construction

In November 2011, Sabine Pass Liquefaction entered into the EPC Contract (Train 1 and 2) with Bechtel. Sabine Pass Liquefaction issued a notice to proceed for construction under the EPC Contract (Train 1 and 2) in August 2012.

In December 2012, Sabine Pass Liquefaction entered into the EPC Contract (Train 3 and 4) with Bechtel. Under the EPC Contract (Train 3 and 4), if Sabine Pass Liquefaction fails to issue notice to proceed to Bechtel by December 31, 2013, then either Sabine Pass Liquefaction or Bechtel may terminate the EPC Contract (Train 3 and 4), and Bechtel will be paid costs reasonably incurred on account of such termination and a lump sum of $5.0 million. The Trains are in various stages of development, as described above.

The total contract price of the EPC Contract (Train 1 and 2) is approximately $3.97 billion, reflecting amounts incurred under change orders through December 31, 2012. Total expected capital costs for Train 1 and Train 2 are estimated to be between $4.5 billion and $5.0 billion before financing costs, including estimated owner's costs and contingencies. Budgeted total all-in costs for Train 1 and Train 2 are estimated to be between $5.5 billion and $6.0 billion, including financing costs and interest expense during construction. The contract price of the EPC Contract (Train 3 and 4) is $3.77 billion, only subject to adjustment by change order (including if Sabine Pass Liquefaction issues the notice to proceed after June 1, 2013).

The liquefaction technology to be employed under the EPC Contracts is the ConocoPhillips Optimized Cascade® Process, which was first used at the ConocoPhillips Petroleum Kenai plant built by Bechtel in 1969 in Kenai, Alaska. Bechtel has since designed and/or constructed LNG facilities using the ConocoPhillips Optimized Cascade® technology in Angola, Australia, Egypt, Equatorial Guinea and Trinidad. The design and technology has been proven in over four decades of operation.

Sabine Pass Liquefaction's Trains will require significant amounts of capital to construct and operate and are subject to risks and delays in completion. Even if successfully completed, Train 1 is not expected to operate and generate significant cash flows before the end of 2015.

We currently expect that Sabine Pass Liquefaction's capital resources requirements with respect to Train 1 and Train 2 will be financed through borrowings, equity contributions from Cheniere Partners and cash flows under our SPAs. We believe that with the net proceeds of borrowings, in addition to construction loans and unfunded commitments under the Liquefaction Credit Facility, Sabine Pass Liquefaction will have adequate financial resources available to complete Train 1 and Train 2 and to meet

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its currently anticipated capital, operating and debt service requirements. We currently project that Sabine Pass Liquefaction will generate cash flow from operations by the end of 2015, when Train 1 is anticipated to achieve initial LNG production, and that such cash flow will be sufficient to meet Sabine Pass Liquefaction's ongoing capital and operating requirements and to pay the interest on its outstanding debt relating to Train 1 and Train 2.

Pipeline Facilities

Cheniere Creole Trail Pipeline, L.P. ("Creole Trail"), an indirect wholly owned subsidiary of Cheniere, owns the Creole Trail Pipeline, a 94-mile pipeline interconnecting the Sabine Pass LNG terminal with a number of large interstate pipelines, including Natural Gas Pipeline Company of America, Transcontinental Gas Pipeline Corporation, Tennessee Gas Pipeline Company, Florida Gas Transmission Company, Texas Eastern Gas Transmission, and Trunkline Gas Company, as well as the intrastate pipeline system of Bridgeline Holdings, L.P.

Sabine Pass Liquefaction has entered into a transportation precedent agreement to secure firm pipeline transportation capacity with Creole Trail and two other pipelines for Train 1 and Train 2. Creole Trail filed an application with the FERC in April 2012 for certain modifications to allow the Creole Trail Pipeline to be able to transport natural gas to the Sabine Pass LNG terminal. Creole Trail estimates the capital costs to modify the Creole Trail Pipeline will be approximately $90 million. The modifications are expected to be in service in time for the commissioning and testing of Train 1 and Train 2.

We have entered into an agreement with Cheniere to purchase the equity interests of the entities that own the Creole Trail Pipeline if, among other things, we obtain acceptable financing for the purchase price. The consideration to be paid by us for the Creole Trail Pipeline is 12 million Class B units and $300 million, plus any costs incurred by Creole Trail from August 2012 until the purchase date, including, if applicable, any portion of the expected $90 million for pipeline modifications.

Capital Resources

Senior Secured Notes

We currently have three series of senior notes outstanding: $1,665.0 million of 7½% Senior Secured Notes due 2016 issued by Sabine Pass LNG (the "2016 Notes"), $420.0 million of 6.50% of Senior Secured Notes due 2020 issued by Sabine Pass LNG (the "2020 Notes" and collectively with the 2016 Notes, the "Sabine Pass LNG Senior Notes") and $1,500.0 million of 5.625% Senior Secured Notes due 2021 issued by Sabine Pass Liquefaction (the "Sabine Liquefaction Notes"). Interest on the 2016 Notes is payable semi-annually in arrears on May 30 and November 30 of each year, interest on the 2020 Notes is payable semi-annually in arrears on May 1 and November 1 of each year and interest on the Sabine Liquefaction Notes is payable semi-annually in arrears on February 1 and August 1 of each year. Subject to permitted liens, the Sabine Pass LNG 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 Sabine Pass LNG's operating assets, and the Sabine Liquefaction Notes are secured on a first-priority basis by a security interest in all of Sabine Pass Liquefaction's equity interests and substantially all of Sabine Pass Liquefaction's assets.

Sabine Pass LNG may redeem some or all of the 2016 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 2016 Notes or the excess of (i) the present value at such redemption date of the redemption price of the 2016 Notes plus all required interest payments due on the 2016 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 (ii) the principal amount of the 2016 Notes, if greater.

Sabine Pass LNG may redeem some or all of the 2020 Notes at any time on or after November 1, 2016 at fixed redemption prices specified in the indenture governing the 2020 Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also redeem some or all of the 2020 Notes at any time prior to November 1, 2016 at a "make-whole" price set forth in the indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, Sabine Pass LNG may redeem up to 35% of the aggregate principal amount of the 2020 Notes at a redemption price of 106.5% of the principal amount of the 2020 Notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date, in an amount not to exceed the net proceeds of one or more completed equity offerings as long as we redeem the 2020 Notes within 180 days of the closing date for such equity offering and at least 65% of the aggregate principal amount of the 2020 Notes originally issued remains outstanding after the redemption.

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Sabine Pass Liquefaction may redeem some or all of the Sabine Liquefaction Notes at any time prior to November 1, 2020 at a redemption price equal to the "make-whole" price set forth in the indenture governing the Sabine Liquefaction Notes, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass Liquefaction may also at any time on or after November 1, 2020, redeem the Sabine Liquefaction Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the Sabine Liquefaction Notes to be redeemed, plus accrued and unpaid interest, if any, to the date of redemption.

Under the indentures governing the Sabine Pass LNG Senior Notes, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted under the Sabine Pass LNG Senior Notes only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the indentures governing the Sabine Pass LNG Senior Notes. Under the indenture governing the Sabine Liquefaction Notes, Sabine Pass Liquefaction may not make any distributions until, among other requirements, substantial completion of Train 1 and Train 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverage ratio of 1.25:1.00 is satisfied.

Liquefaction Credit Facility

In July 2012, Sabine Pass Liquefaction entered into a construction/term loan facility in an amount up to $3.626 billion available to us in four tranches solely to fund Liquefaction Project costs for Train 1 and Train 2, the related debt service reserve account up to an amount equal to six months of scheduled debt service and the return of equity and affiliate subordinated debt funding to Cheniere or its affiliates up to an amount that will result in senior debt being no more than 65% of our total capitalization. The four tranches are as follows:

• Tranche 1: up to $200 million;

• Tranche 2: up to $150 million;

• Tranche 3: up to $150 million; and

• Tranche 4: up to $3.126 billion.

The principal of the construction/term loan is repayable in quarterly installments beginning on the first quarter-end date to occur at least three months after the earlier of the date on which all conditions for project completion under the Liquefaction Credit Facility have been satisfied and the date on which all of the construction/term loan commitments have been used or terminated.

Sabine Pass Liquefaction may make borrowings based on LIBOR plus the applicable margin (3.50% prior to the Liquefaction Project completion date or 3.75% thereafter) or the base rate plus the applicable margin (2.50% prior to the Liquefaction Project completion date or 2.75% thereafter). Sabine Pass Liquefaction is also required to pay commitment fees on the undrawn amount. Sabine Pass Liquefaction is party to interest rate protection agreements with respect to no less than 75% (calculated on a weighted average basis) of the projected outstanding balance for a term of no less than seven years on terms reasonably satisfactory to us and the required secured parties. Upon our incurrence of any replacement debt prior to June 30, 2013, including the sale of the Sabine Liquefaction Notes, Tranche 4 of the Liquefaction Credit Facility commitments, in an amount equal to the proceeds from such replacement debt less certain fees and expenses, will be suspended and extended until December 31, 2013 unless expansion debt shall have been approved prior to such date. Subject to approval by Sabine Pass Liquefaction's lenders, Sabine Pass Liquefaction currently intends to use such suspended commitments to finance the construction of Train 3 and Train 4.

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, 2012, 2011 and 2010. 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.

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	Year Ended December 31,
	2012			2011			2010
Sources of cash and cash equivalents
Proceeds from sales of Class B units	$	1,887,342		$	—		$	—
Proceeds from debt issuances	520,000			—			—
Proceeds from sale of partnership common and general partner units	250,022			70,157			—
Operating cash flow	—			14,249			104,137
Total sources of cash and cash equivalents	2,657,364			84,406			104,137
Uses of cash and cash equivalents
LNG terminal costs, net	(1,118,457		)	(7,137		)	(4,955		)
Repayment of 2013 Notes	(550,000		)	—			—
Investment in restricted cash and cash equivalents	(343,877		)	—			—
Debt issuance and deferred financing costs	(222,378		)	—			—
Distributions to unitholders	(57,821		)	(48,149		)	(163,249		)
Operating cash flow	(26,214		)	—			—
Advances under long-term contracts	(740		)	(1,054		)	(121		)
Other	—			—			(5		)
Total uses of cash and cash equivalents	(2,319,487		)	(56,340		)	(168,330		)
Net increase (decrease) in cash and cash equivalents	337,877			28,066			(64,193		)
Cash and cash equivalents—beginning of period	81,415			53,349			117,542
Cash and cash equivalents—end of period	$	419,292		$	81,415		$	53,349

Proceeds from Sales of Class B units

During the year ended December 31, 2012, we issued and sold an aggregate of 133.3 million Class B units to Cheniere and Blackstone at a price of $15.00 per Class B unit, resulting in total net proceeds of $1,887.3 million.

Proceeds from Debt Issuances and Debt Issuance and Deferred Financing Costs

In October 2012, Sabine Pass LNG issued the $420.0 million 2020 Notes. In July 2012, Sabine Pass Liquefaction entered into the $3.6 billion Liquefaction Credit Facility. Sabine Pass Liquefaction made $100.0 million of borrowings under the Liquefaction Credit Facility in August 2012 after meeting the required conditions precedent to the initial advance. Debt issuance costs primarily relate to $212.8 million paid by Sabine Pass Liquefaction upon the closing of the Liquefaction Credit Facility.

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Proceeds from the Sale of Partnership Common and General Partner Units

In September 2012, we sold 8.0 million common units in an underwritten public offering at a price of $25.07 per common unit for net cash proceeds of $194.0 million. We also received $45.1 million in net cash proceeds from our general partner in connection with the exercise of its right to maintain its 2% ownership interest in us during the year ended December 31, 2012.

In September 2011, we 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. We received net cash proceeds of $70.2 million from the offering (including proceeds from our general partner in connection with the exercise of its right to maintain its 2% ownership interest in us), which were used for general business purposes, including development costs for the Liquefaction Project.

In January 2011, we 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 the Liquefaction Project. During the year ended December 31, 2011, we sold 0.5 million common units for net cash proceeds of $9.0 million. During the year endedDecember 31, 2012, we sold 0.5 million common units for net cash proceeds of $11.1 million. We paid $0.3 million in commissions to Miller Tabak + Co., Inc., as sales agent, in connection with the at-the-market program during each of the years ended December 31, 2012 and 2011.

Operating cash flow

Operating cash flow decreased $40.5 million from 2011 to 2012. The decrease in operating cash flow primarily resulted from increased costs incurred to develop and manage the construction of Train 1 and Train 2, and decreased LNG cargo export loading fee revenue.

Operating cash flow decreased $89.9 million from 2010 to 2011 primarily due to the June 2010 TUA assignment from Cheniere Marketing to Cheniere Investments, effective July 1, 2010, that resulted in the TUA payments being made by Cheniere Investments, our wholly owned subsidiary, instead of being received from Cheniere Marketing. In addition, operating cash flow decreased from 2010 to 2011 as a result of increased development costs in 2011 associated with the Liquefaction Project.

LNG Terminal and Pipeline Construction-in-Process, net

Capital expenditures for the Sabine Pass LNG terminal were $1,118.5 million, $7.1 million and $5.0 million in the years ended December 31, 2012, 2011 and 2010, respectively. We began capitalizing costs associated with the construction of Train 1 and Train 2 of the Liquefaction Project as construction-in-process during the second quarter of 2012.

Repayment of 2013 Notes

During the fourth quarter of 2012, Sabine Pass LNG repurchased its $550.0 million 2013 Notes. Funds used for the repurchase included proceeds received from the 2020 Notes and from an equity contribution from us.

Investment in Restricted Cash and Cash Equivalents

During 2012, we invested $343.9 million in restricted cash and cash equivalents. This investment was a result of the $1,458.6 million of restricted cash and cash equivalents from the proceeds of Class B unit sales that was partially offset by the use of $1,114.7 million of restricted cash for the construction of Train 1 and Train 2 of the Liquefaction Project.

Distributions to owners

We made $57.8 million, $48.1 million and $163.2 million of distributions to our common and subordinated unitholders and to our general partner in the years ended December 31, 2012, 2011 and 2010, respectively. The decreased amount of distributions to owners from the year ended December 31, 2010 as compared to the years ended December 31, 2011 and 2012 primarily resulted from the TUA assignment from Cheniere Marketing to Cheniere Investments, effective July 1, 2010, which resulted in the TUA payments being made by Cheniere Investments, our wholly owned subsidiary, instead of Cheniere Marketing and decreased our available cash in excess of the common unit and general partner distributions. As a result of Cheniere Marketing's assignment of its TUA to Cheniere Investments, we have not paid distributions on our subordinated units since the distribution made with respect to the quarter ended March 31, 2010.

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Cash Distributions to Unitholders

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from accumulated operating surplus. The following provides a summary of distributions paid by us during the year endedDecember 31, 2012:

				Total Distribution
				(in thousands)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Common Units		Subordinated Units		General Partner Units
February 14, 2012	October 1, 2011 - December 31, 2011	$	0.425	$	13,176	$	—	$	269
May 15, 2012	January 1, 2012 - March 31, 2012	$	0.425	$	13,323	$	—	$	272
August 15, 2012	April 1, 2012 - June 30, 2012	$	0.425	$	13,383	$	—	$	273
November 14, 2012	July 1, 2012 - September 30, 2012	$	0.425	$	16,783	$	—	$	343

The subordinated units will receive distributions only to the extent we have available cash above the minimum quarterly distributions requirement for our common unitholders and general partner along with certain reserves. Such available cash could be generated through new business development or fees received from Cheniere Marketing under the VCRA. The ending of the subordination period and conversion of the subordinated units into common units will depend upon future business development.

In 2012, we issued Class B units, a new class of equity interests representing limited partner interests in us, in connection with the development of the Liquefaction Project. The Class B units are not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale of substantially all of our assets). The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basis beginning on the initial purchase of the Class B units, and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The holders of Class B units have a preference over the holders of the subordinated units in the event of a liquidation (or merger, combination or sale of substantially all of our assets).

On January 22, 2013, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid to owners of record on February 1, 2013 for the period from October 1, 2012 to December 31, 2012.

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, 2012 (in thousands).

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	Payments Due for Years Ended December 31,
	Total		2013		2014 - 2015		2016 - 2017		Thereafter
Construction and purchase obligations (1)	$	3,044,606	$	1,286,184	$	1,532,576	$	225,846	$	—
Long-term debt (excluding interest) (2)	2,185,500		—		—		1,665,500		520,000
Operating lease obligations (3) (4)	279,777		9,625		19,229		19,039		231,884
Service contracts:
Affiliate Sabine Pass LNG O&M Agreement (5)	28,176		1,682		3,365		3,365		19,764
Affiliate Sabine Pass LNG MSA (5)	112,711		6,729		13,458		13,458		79,066
Affiliate Sabine Pass Liquefaction O&M Agreement (5)	62,769		7,828		10,676		7,432		36,833
Affiliate Sabine Pass Liquefaction MSA (5)	351,910		31,313		42,704		38,477		239,416
Affiliate services agreement (5)	190,366		11,198		22,396		22,396		134,376
Cooperative endeavor agreements (5)	9,813		2,453		4,907		2,453		—
Other obligation (6)	1,113		1,113		—		—		—
Total	$	6,266,741	$	1,358,125	$	1,649,311	$	1,997,966	$	1,261,339

(1) A discussion of these obligations can be found at Note 15—"Commitments and Contingencies" of our Notes to Consolidated Financial Statements.

(2) Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2012, our cash payments for interest would be $202.8 million in 2013, $201.6 million in 2014, $201.6 million in 2015, $191.2 million in 2016, $76.7 million in 2017 and $155.4 million for the remaining years for a total of $1,029.3 million.  See Note 11—"Long-Term Debt" of our Consolidated Financial Statements.

(3) A discussion of these obligations can be found in Note 14—"Leases" of our Consolidated Financial Statements.

(4) Minimum lease payments have not been reduced by a minimum sublease rental of $112.8 million due in the future under non-cancelable tug boat subleases.

(5) A discussion of these obligations can be found in Note 13—"Related Party Transactions" of our Consolidated Financial Statements.

(6) Other obligation consists of LNG terminal security services.

Results of Operations

2012 vs. 2011

Our consolidated net income decreased $119.1 million, from $31.0 million of net income in 2011 to $150.1 million of net loss in 2012. This increase in net loss primarily resulted from loss on early extinguishment of the 2013 Notes, increased costs incurred to manage the construction of Train 1 and Train 2 of the Liquefaction Project, decreased revenues, increased operating and maintenance expense and increased development expense. Loss on early extinguishment of debt increased from zero in 2011 to $42.6 million in 2012 primarily as a result of make-whole payments associated with the early repayments in full of the 2013 Notes. Our general and administrative expense (including affiliate expense) increased $40.2 million, from $26.0 million in 2011 to $66.2 million in 2012. This increase in general and administrative expense primarily resulted from increased costs incurred to manage the construction of Train 1 and Train 2 of the Liquefaction Project. Total revenues decreased $19.5 million, from $283.8 million in 2011 to $264.3 million in 2012. This decrease in revenues (including affiliate revenues) primarily resulted from decreased LNG cargo export loading fee revenue, decreased revenues earned under the VCRA, and a provision for loss on a firm purchase commitment for LNG inventory that will be used to restore the heating value of vaporized LNG to conform to natural gas pipeline specifications. Operating and maintenance expense (including affiliate expense) increased $18.0 million, from $33.7 million in 2011 to $51.8 million in 2012. This increase primarily resulted from the loss incurred to purchase LNG to maintain the cryogenic readiness of the Sabine Pass LNG terminal and increased dredging services in 2012. Development expense (including affiliate expense) increased $3.8 million, from $36.5 million in 2011 to $40.2 million in 2012. This increase in development expense resulted from costs incurred to develop the Liquefaction Project.

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2011 vs. 2010

Our consolidated net income decreased $138.6 million, from $107.6 million of net income in 2010 to $31.0 million of net loss in 2011. This decrease in net income primarily resulted from the TUA assignment from Cheniere Marketing to Cheniere Investments, effective July 1, 2010 that resulted in the TUA payments being made by Cheniere Investments, our wholly owned subsidiary, instead of Cheniere Marketing. Beginning July 1, 2010, our affiliate revenues reflect only tug service revenue and the amount of income earned under the VCRA from Cheniere Marketing because the affiliate revenues earned by Sabine Pass LNG from Cheniere Investments' capacity payments under the TUA are eliminated upon consolidation of our financial statements. In addition, the decrease in net income in 2011 was a result of increases in development expenses related to the Liquefaction Project. These decreases in net income were partially offset by decreased operating and maintenance expenses and decreased development expense in 2011 compared to 2010. Operating and maintenance expense (including affiliate expense) decreased $5.5 million, from $39.2 million in 2010 to $33.7 million in 2011. This decrease primarily resulted from decreased fuel costs in 2011 compared to 2010 as a result of efficiencies in our LNG inventory management.

Off-Balance Sheet Arrangements

As of December 31, 2012, 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.

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 LNG terminal projects 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.

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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.

Derivatives

We use derivative instruments from time to time to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory, to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal, and to hedge the exposure to volatility in a portion of the floating-rate interest payments under the Liquefaction Credit Facility. We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 8—"Financial Instruments" of our Notes to Consolidated Financial Statements.

Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. We record changes in the fair value of our derivative positions 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 and interest rates change.

Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are recognized currently in earnings. Gains and losses in positions to hedge the cash flows attributable to the future sale of LNG inventory are classified as 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 have elected cash flow hedge accounting for derivatives that we use to hedge the exposure to volatility in floating-rate interest payments. Changes in fair value of derivative instruments designated as cash flow hedges, to the extent the hedge is effective, are recognized in accumulated other comprehensive loss on our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive loss into interest expense in our Consolidated Statements of Operations as the hedged item is recognized. Any change in the fair value resulting from ineffectiveness is recognized immediately as derivative gain (loss) on our Consolidated Statements of Operations. We use regression analysis to determine whether we expect a derivative to be highly effective as a cash flow hedge prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges have been effective. We perform these effectiveness tests prior to designation for all new hedges and on a quarterly basis for all existing hedges. We calculate the actual amount of ineffectiveness on our cash flow hedges using the "dollar offset" method, which compares changes in the expected cash flows of the hedged transaction to changes in the value of expected cash flows from the hedge. We discontinue hedge accounting when our effectiveness tests indicate that a derivative is no longer highly effective as a hedge; when the derivative expires or is sold, terminated or exercised; when the hedged item matures, is sold or repaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but continue to hold the derivative, we begin to apply mark-to-market accounting at that time.

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.

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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.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded as an other current asset and not netted within the derivative fair value. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

Sabine Pass LNG has entered into certain long-term TUAs with unaffiliated third parties for regasification capacity at our Sabine Pass LNG terminal. We are dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective TUAs. We have mitigated this credit risk by securing TUAs for a significant portion of our regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA.

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 property, plant and equipment for 2012, 2011 or 2010.

Income Taxes

We are not subject to either federal or state income taxes, as the partners are taxed individually on their proportionate share of our earnings. At December 31, 2012, the tax basis of our assets and liabilities was $290.6 million less than the reported amounts of our assets and liabilities. 

In November 2006, Sabine Pass LNG and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass LNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass LNG will pay to Cheniere an amount equal to the state and local tax that Sabine Pass LNG would be required to pay if Sabine Pass LNG's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass LNG under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass LNG. The agreement is effective for tax returns due on or after January 1, 2008.

In August 2012, Sabine Pass Liquefaction and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass Liquefaction and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass Liquefaction will pay to Cheniere an amount equal to the state and local tax that Sabine Pass Liquefaction would be required to pay if Sabine Pass Liquefaction's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass

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Liquefaction under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass Liquefaction. The agreement is effective for tax returns due on or after August 2012.

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 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 units, reduced estimates of future cash flows of our business or disruptions to our business could lead to an impairment charge of our long-lived assets 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, 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, valuations of derivative instruments 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.

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.

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:

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. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is zero. Therefore, we have not recorded an asset retirement obligation associated with the Sabine Pass LNG terminal.

Recent Accounting Standards

In May 2011, the Financial Accounting Standards Board ("FASB") issued guidance that further addresses fair value measurement accounting and related disclosure requirements.  The guidance clarifies the FASB's intent regarding the application of existing fair value measurement and disclosure requirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for other fair value measurements.  The guidance is to be applied prospectively and is effective for periods beginning after December 15, 2011.  We adopted this guidance effective January 1,

52

2012.  The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows, as it only expanded disclosures.

In June 2011, the 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 adopted this guidance in our first fiscal quarter ending March 31, 2012. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows as it only required a change in the format of the current presentation.

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 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 exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal ("Fuel Derivatives"). We use one-day value at risk ("VaR") with a 95% confidence interval and other methodologies for market risk measurement and control purposes of our LNG Inventory Derivatives and Fuel Derivatives. The VaR is calculated using the Monte Carlo simulation method. The table below provides information about our LNG Inventory Derivatives and Fuel Derivatives that are sensitive to changes in natural gas prices and interest rates as of December 31, 2012.

Hedge Description	Hedge Instrument	Contract Volume (MMBtu)	Price Range ($/MMBtu)	Final Hedge Maturity Date	Fair Value (in thousands)			VaR (in thousands)
LNG Inventory Derivatives	Fixed price natural gas swaps	1,518,095	$3.366 - $3.893	May 2013	$	232		$	25
Fuel Derivatives	Fixed price natural gas swaps	1,095,000	$3.351 - $4.050	January 2014	(98		)	5

We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the Liquefaction Credit Facility ("Interest Rate Derivatives"). In order to test the sensitivity of the fair value of the Interest Rate Derivatives to changes in interest rates, management modeled a 10% change in the forward 1-month LIBOR curve across the full 7-year term of the Interest Rate Derivatives. This 10% change in interest rates resulted in a change in the fair value of the Interest Rate Derivatives of $19.2 million. The table below provides information about our Interest Rate Derivatives that are sensitive to changes in the forward 1-month LIBOR curve as of December 31, 2012.

Hedge Description	Hedge Instrument	Initial Notional Amount	Maximum Notional Amount	Fixed Interest Rate Range (%)	Final Hedge Maturity Date	Fair Value (in thousands)			10% Change in LIBOR (in thousands)
Interest Rate Derivatives	Interest rate swaps	$20.0 million	$2.9 billion	1.978 - 1.981	July 2019	$	(26,424	)	$	19,241

53

ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P.

Management’s Report to the Unitholders of Cheniere Energy Partners, L.P.	55
Reports of Independent Registered Public Accounting Firm—Ernst & Young LLP	56
Consolidated Balance Sheets	58
Consolidated Statements of Operations	59
Consolidated Statements of Comprehensive Loss	60
Consolidated Statements of Partners’ and Owners’ Capital (Deficit)	61
Consolidated Statements of Cash Flows	62
Notes to Consolidated Financial Statements	63
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data	88

54

MANAGEMENT’S REPORT TO THE UNITHOLDERS OF CHENIERE ENERGY PARTNERS, L.P.

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 Partners, L.P. ("Cheniere Partners") and its subsidiaries. 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 Partners' 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 Partners' maintained effective internal control over financial reporting as of December 31, 2012, based on criteria in Internal Control—Integrated Framework issued by the COSO.

Cheniere Partners’ independent auditors, Ernst & Young LLP, have issued an audit report on Cheniere Partners’ internal control over financial reporting as of December 31, 2012, which is contained in this Form 10-K.

Management’s Certifications

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

Cheniere Energy Partners, L.P.
By:	Cheniere Energy Partners GP, LLC,
	Its general partner

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

55

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Cheniere Energy Partners GP, LLC, and

Unitholders of Cheniere Energy Partners, L.P.

We have audited the accompanying consolidated balance sheets of Cheniere Energy Partners, L.P. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), partners' and owners' capital (deficit), and cash flows for each of the three years in the period ended December 31, 2012. 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 Partners, L.P. and subsidiaries at December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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 Partners, L.P.'s internal control over financial reporting as of December 31, 2012, 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 22, 2013 expressed an unqualified opinion thereon.

/s/    ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

February 22, 2013

56

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Cheniere Energy Partners GP, LLC, and

Unitholders of Cheniere Energy Partners, L.P.

We have audited Cheniere Energy Partners, L.P. and subsidiaries' internal control over financial reporting as of December 31, 2012, 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 Partners, L.P. 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 Partners, L.P. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, 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 Partners, L.P. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), partners' and owners' capital (deficit), and cash flows for each of the three years in the period ended December 31, 2012, and our report dated February 22, 2013 expressed an unqualified opinion thereon.

/s/    ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

February 22, 2013

57

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

	December 31,
	2012			2011
ASSETS
Current assets
Cash and cash equivalents	$	419,292		$	81,415
Restricted cash and cash equivalents	92,519			13,732
Accounts and interest receivable	44			525
Accounts receivable—affiliate	2,005			328
Advances to affiliate	4,987			692
LNG inventory	2,625			473
LNG inventory - affiliate	4,420			4,369
Prepaid expenses and other	6,652			7,976
Total current assets	532,544			109,510
Non-current restricted cash and cash equivalents	272,425			82,394
Property, plant and equipment, net	2,704,895			1,514,416
Debt issuance costs, net	220,949			17,622
Other	17,465			13,358
Total assets	$	3,748,278		$	1,737,300
LIABILITIES AND PARTNERS’ EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	73,760		$	704
Accounts payable—affiliate	1,122			530
Accrued liabilities	47,403			16,751
Accrued liabilities—affiliate	5,791			3,794
Deferred revenue	26,540			26,629
Deferred revenue—affiliate	696			688
Other	98			2,722
Total current liabilities	155,410			51,818
Long-term debt, net of discount	2,167,113			2,192,418
Deferred revenue	21,500			25,500
Deferred revenue—affiliate	14,720			12,266
Long-term derivative liability	26,424			—
Other non-current liabilities	303			317
Commitments and contingencies
Partners' capital (deficit)
Common unitholders (39,488,488 and 31,003,154 units issued and outstanding at December 31, 2012 and 2011, respectively)	448,412			(52,774		)
Class B unitholders (133,333,334 units and zero units issued and outstanding as of December 31, 2012 and 2011, respectively)	(37,342		)	—
Subordinated unitholders (135,383,831 units issued and outstanding at December 31, 2012 and 2011)	949,482			(479,197		)
General partner interest (2% interest with 6,289,911 units and 3,395,653 units issued and outstanding at December 31, 2012 and 2011, respectively)	29,496			(13,048		)
Accumulated other comprehensive loss	(27,240		)	—
Total partners’ capital (deficit)	1,362,808			(545,019		)
Total liabilities and partners’ equity (deficit)	$	3,748,278		$	1,737,300

See accompanying notes to consolidated financial statements.

58

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

	Year Ended December 31,
	2012			2011			2010
Revenues
Revenues	$	256,354		$	269,183		$	268,328
Revenues—affiliate	7,973			14,607			130,954
Total revenues	264,327			283,790			399,282
Expenses
Operating and maintenance expense	35,457			21,827			27,069
Operating and maintenance expense—affiliate	16,300			11,918			12,090
Depreciation expense	42,551			42,943			42,299
Development expense	37,559			32,448			8,738
Development expense—affiliate	2,677			4,025			1,824
General and administrative expense	10,303			5,534			6,190
General and administrative expense—affiliate	55,940			20,469			20,275
Total expenses	200,787			139,164			118,485
Income from operations	63,540			144,626			280,797
Other income (expense)
Interest expense, net	(171,646		)	(173,590		)	(174,016		)
Loss on early extinguishment of debt	(42,587		)	—			—
Derivative gain (loss), net	58			(2,251		)	461
Other	499			196			326
Total other expense	(213,676		)	(175,645		)	(173,229		)
Net income (loss)	$	(150,136	)	$	(31,019	)	$	107,568
Basic and diluted net income per common unit	$	0.27		$	1.23		$	1.70
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation	33,470			27,910			26,416

See accompanying notes to consolidated financial statements.

59

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

	Year Ended December 31,
	2012			2011			2010
Net income (loss)	$	(150,136	)	$	(31,019	)	$	107,568
Other comprehensive loss
Interest rate cash flow hedges
Loss on settlements retained in other comprehensive income	(136		)	—			—
Change in fair value of interest rate cash flow hedges	(27,104		)	—			—
Total other comprehensive loss	(27,240		)	—			—
Comprehensive income (loss)	$	(177,376	)	$	(31,019	)	$	107,568

See accompanying notes to consolidated financial statements.

60

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ AND

OWNERS’ CAPITAL (DEFICIT)

(in thousands)

	Common Unitholders			Class B Unitholders			Subordinated Unitholders			General Partner Interest			Accumulated Other Comprehensive Loss			Total Partners' Capital (Deficit)
Balance, December 31, 2009	$	(41,494	)	$	—		$	(427,026	)	$	(11,807	)	$	—		$	(480,327	)
Net income	17,211			—			88,206			2,151			—			107,568
Distributions	(44,908		)	—			(115,076		)	(3,265		)	—			(163,249		)
Balance, December 31, 2010	(69,191		)	—			(453,896		)	(12,921		)	—			(536,008		)
Net loss	(5,098		)	—			(25,301		)	(620		)	—			(31,019		)
Sale of common and general partner units	68,701			—			—			1,456			—			70,157
Distributions	(47,186		)	—			—			(963		)	—			(48,149		)
Balance at December 31, 2011	(52,774		)	—			(479,197		)	(13,048		)	—			(545,019		)
Net loss	(28,351		)	—			(114,678		)	(7,107		)	—			(150,136		)
Sale of common and general partner units	204,878			—			—			45,144			—			250,022
Distributions	(56,665		)	—			—			(1,156		)	—			(57,821		)
Non-cash contributions	—			—			—			5,663			—			5,663
Interest rate cash flow hedges	—			—			—			—			(27,240		)	(27,240		)
Sale of Class B units	—			1,887,339			—			—			—			1,887,339
Beneficial conversion feature of Class B units	386,473			(1,950,000		)	1,563,527			—			—			—
Amortization of beneficial conversion feature of Class B units	(5,149		)	25,319			(20,170		)	—			—			—
Balance at December 31, 2012	$	448,412		$	(37,342	)	$	949,482		$	29,496		$	(27,240	)	$	1,362,808

See accompanying notes to consolidated financial statements.

61

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2012			2011				2010
Cash flows from operating activities
Net income (loss)	$	(150,136	)	$	(31,019	)		$	107,568
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation	42,551			42,943				42,299
Use of restricted cash and cash equivalents	75,060			—				—
Non-cash LNG inventory—affiliate write-downs	—			10,600				—
Amortization of debt discount	4,695			4,695				4,695
Amortization of debt issuance costs	4,362			4,382				4,863
Non-cash derivative (gain) loss	(619		)	(195		)		124
Loss on early extinguishment of debt	1,470			—				—
Other	3,496			—				—
Changes in operating assets and liabilities:
Accounts and interest receivable	481			853				(626		)
Accounts receivable—affiliate	(1,677		)	384				2,874
Accounts payable and accrued liabilities	1,960			(1,173		)		3,035
Accounts payable and accrued liabilities—affiliate	2,412			(1,640		)		2,566
Deferred revenue—affiliate	8			15				(62,833		)
Deferred revenue	(4,089		)	(3,964		)		(3,864		)
Advances to affiliate	(4,764		)	2,851				1,815
LNG inventory—affiliate	(51		)	(14,969		)		—
Other	(1,373		)	486				1,621
Net cash provided by (used in) operating activities	(26,214		)	14,249				104,137
Cash flows from investing activities
Use of restricted cash and cash equivalents	1,114,742			—				—
LNG terminal costs, net	(1,118,457		)	(7,137		)		(4,955		)
Advances under long-term contracts	(740		)	(1,054		)		(121		)
Net cash used in investing activities	(4,455		)	(8,191		)		(5,076		)
Cash flows from financing activities
Proceeds from sale of Class B units, net	1,887,342			—				—
Proceeds from 2020 Notes	420,000			—				—
Proceeds from Liquefaction Credit Facility	100,000			—				—
Proceeds from sale of partnership units	250,022			70,157				—
Investment in restricted cash and cash equivalents	(1,458,619		)	—			—	—
Repayment of 2013 Notes	(550,000		)	—				—
Debt issuance and deferred financing costs	(222,378		)	—				—
Distributions to owners	(57,821		)	(48,149		)		(163,249		)
Other	—			—				(5		)
Net cash provided by (used in) financing activities	368,546			22,008				(163,254		)
Net increase (decrease) in cash and cash equivalents	337,877			28,066				(64,193		)
Cash and cash equivalents—beginning of period	81,415			53,349				117,542
Cash and cash equivalents—end of period	$	419,292		$	81,415			$	53,349

 See accompanying notes to consolidated financial statements.

62

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—NATURE OF OPERATIONS

Cheniere Energy Partners, L.P. ("Cheniere Partners") is a publicly-held Delaware limited partnership formed on November 21, 2006. As of December 31, 2012, Cheniere Energy, Inc. ("Cheniere") owned 59.5% of the limited partnership through its wholly owned subsidiaries, Cheniere LNG Holdings, LLC ("Holdings"), Cheniere Common Units Holding, LLC ("Cheniere Common Units Holding"), Cheniere Subsidiary Holdings, LLC ("Subsidiary Holdings") and Cheniere Energy Partners GP, LLC ("Cheniere GP"). Cheniere Partners was formed to own and operate the Sabine Pass liquefied natural gas ("LNG") terminal located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal has regasification facilities owned by our wholly owned subsidiary, Sabine Pass LNG, L.P. ("Sabine Pass LNG") that includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels of up to 265,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Approximately one-half of the receiving capacity at the Sabine Pass LNG terminal is contracted to two multinational energy companies.

We are developing natural gas liquefaction facilities (the "Liquefaction Project") at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction". We plan to construct up to six Trains (each in sequence, "Train 1", "Train 2", "Train 3", "Train 4", "Train 5" and "Train 6"), which are in various stages of development. Each Train has a nominal production capacity of approximately 4.5 mmtpa.

Unless the context requires otherwise, references to "Cheniere Partners", "we", "us" and "our" refer to Cheniere Partners and its subsidiaries.

NOTE 2—INITIAL PUBLIC OFFERING

We and Holdings, as a selling unitholder, completed an offering of 13,500,000 Cheniere Partners common units for $21.00 per common unit on March 26, 2007 (the "Cheniere Partners Offering"). Upon the closing of the Cheniere Partners Offering, the following transactions occurred: 

• Holdings contributed through us to our wholly owned subsidiary, Cheniere Energy Investments, LLC ("Cheniere Investments"), all of its equity interests in Sabine Pass LNG-GP, LLC ("Sabine Pass GP") and Sabine Pass LNG-LP, LLC ("Sabine Pass LP"), which own all of the equity interests in Sabine Pass LNG, the owner of the entire interest in the Sabine Pass LNG terminal; 

• we issued to Holdings 21,362,193 common units and 135,383,831 subordinated units; 

• we issued to our general partner, a direct wholly owned subsidiary of Holdings, 3,302,045 general partner units representing a 2% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash that we distribute in excess of $0.489 per unit per quarter; 

• we issued 5,054,164 common units to the public in the Cheniere Partners Offering; 

• Holdings sold 8,445,836 common units to the public in the Cheniere Partners Offering, after which Holdings and the public held an aggregate 89.8% and 8.2% limited partner interest in us, respectively; 

• our general partner entered into a services agreement with an affiliate of Cheniere under which the affiliate provides various general and administrative services for an annual administrative fee of $10.0 million (adjusted for inflation after January 1, 2007), with payment having commenced January 1, 2009; provided that the fee is currently structured as a non-accountable overhead reimbursement charge of $2.8 million per quarter (indexed for inflation); and 

• we entered into a services and secondment agreement with an affiliate of Cheniere pursuant to which certain employees of the Cheniere affiliate have been seconded to our general partner to provide operating and routine maintenance services with respect to the Sabine Pass LNG terminal.

We received $98.4 million of net proceeds, after deducting the underwriting discount and structuring fee, upon issuance of 5,054,164 common units to the public in the Cheniere Partners Offering. Holdings received $164.5 million of net proceeds, after deducting the underwriting discount and structuring fee, upon its sale of 8,445,836 common units. We did not receive any proceeds

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from the sale of common units by Holdings. We used all of our net proceeds of $98.4 million from the sale of our common units in the Cheniere Partners Offering to purchase U.S. Treasury securities that funded a distribution reserve for payment of initial quarterly distributions of $0.425 per common unit, as well as related quarterly distributions to our general partner, through the quarterly distribution made in respect of the quarter ended June 30, 2009. Our common units are traded on the NYSE MKT under the symbol "CQP."

NOTE 3—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 Partners, L.P. 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

Generally, we begin capitalizing the costs of LNG terminal projects 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 terminal use agreements ("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.

Derivatives

We use derivative instruments from time to time to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory, to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal, and to hedge the exposure to volatility in a portion of the floating-rate interest payments under the Liquefaction Credit Facility. We do not offset the fair value amounts of our LNG inventory, fuel and interest rate derivatives, and collateral deposited for such contracts are not netted within the derivative fair value.  We have disclosed

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certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 8—"Financial Instruments" of our Notes to Consolidated Financial Statements.

Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. We record changes in the fair value of our derivative positions 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 and interest rates change.

Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are recognized currently in earnings. Gains and losses in positions to hedge the cash flows attributable to the future sale of LNG inventory are classified as 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 have elected cash flow hedge accounting for derivatives that we use to hedge the exposure to volatility in floating-rate interest payments. Changes in fair value of derivative instruments designated as cash flow hedges, to the extent the hedge is effective, are recognized in accumulated other comprehensive loss on our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive loss into interest expense in our Consolidated Statements of Operations as the hedged item is recognized. Any change in the fair value resulting from ineffectiveness is recognized immediately as derivative gain (loss) on our Consolidated Statements of Operations. We use regression analysis to determine whether we expect a derivative to be highly effective as a cash flow hedge prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges have been effective. We perform these effectiveness tests prior to designation for all new hedges and on a quarterly basis for all existing hedges. We calculate the actual amount of ineffectiveness on our cash flow hedges using the "dollar offset" method, which compares changes in the expected cash flows of the hedged transaction to changes in the value of expected cash flows from the hedge. We discontinue hedge accounting when our effectiveness tests indicate that a derivative is no longer highly effective as a hedge; when the derivative expires or is sold, terminated or exercised; when the hedged item matures, is sold or repaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but continue to hold the derivative, we begin to apply mark-to-market accounting at that time.

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.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded as an other current asset and not netted within the derivative fair value. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

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Sabine Pass LNG has entered into certain long-term TUAs with unaffiliated third parties for regasification capacity at our Sabine Pass LNG terminal. We are dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective TUAs. We have mitigated this credit risk by securing TUAs for a significant portion of our regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA.

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 property, plant and equipment for 2012, 2011 or 2010.

Income Taxes

We are not subject to either federal or state income taxes, as the partners are taxed individually on their proportionate share of our earnings. At December 31, 2012, the tax basis of our assets and liabilities was $290.6 million less than the reported amounts of our assets and liabilities.

In November 2006, Sabine Pass LNG and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass LNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass LNG will pay to Cheniere an amount equal to the state and local tax that Sabine Pass LNG would be required to pay if Sabine Pass LNG's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass LNG under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass LNG. The agreement is effective for tax returns due on or after January 1, 2008.

In August 2012, Sabine Pass Liquefaction and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass Liquefaction and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass Liquefaction will pay to Cheniere an amount equal to the state and local tax that Sabine Pass Liquefaction would be required to pay if Sabine Pass Liquefaction's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass Liquefaction under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass Liquefaction. The agreement is effective for tax returns due on or after August 2012.

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 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

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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 units, reduced estimates of future cash flows for our business 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, 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, valuations of derivative instruments 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.

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.

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:

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. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is zero. Therefore, we have not recorded an asset retirement obligation associated with the Sabine Pass LNG terminal.

Recent Accounting Standards Not Yet Adopted

We have also considered all other newly issued accounting guidance that is applicable to our operations and the preparation of our consolidated financial statements, including that which is not yet effective. We do not believe that any such guidance will have a material impact on our consolidated financial position, results of operations or cash flows.

NOTE 4—RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents consists 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 2013 Notes and 2016 Notes and $420.0 million of 2020 Notes (See Note 11—"Long-Term Debt"). Collectively, the 2013 Notes, 2016 Notes, and 2020 Notes are referred to as the "Senior Notes." Under the indentures governing the Senior Notes (the "Sabine Pass Indentures"), 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

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deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. 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 Indentures.

As of December 31, 2012 and 2011, we classified $17.4 million and $13.7 million, respectively, as current restricted cash and cash equivalents for the payment of interest due within twelve months. As of December 31, 2012 and 2011, we classified the permanent debt service reserve fund of $76.1 million and $82.4 million, respectively, 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.

Liquefaction Reserve

In July 2012, Sabine Pass Liquefaction closed on a $3.6 billion senior secured credit facility (the "Liquefaction Credit Facility"). Under the terms and conditions of the Liquefaction Credit Facility, Sabine Pass Liquefaction is required to deposit all cash received into reserve accounts controlled by a collateral trustee. Therefore, all of Sabine Pass Liquefaction's cash and cash equivalents are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets. As of December 31, 2012, we classified $100.0 million as non-current restricted cash and cash equivalents held by Sabine Pass Liquefaction as such funds are to be used to acquire non-current assets. As of December 31, 2012, we classified $75.1 million as current restricted cash and cash equivalents held by Sabine Pass Liquefaction as such funds are to be used to pay for current liabilities. As of December 31, 2012, we classified $96.3 million as non-current restricted cash and cash equivalents held by Sabine Pass Liquefaction as such funds are to be used to pay for the Liquefaction Project.

NOTE 5—LNG INVENTORY AND LNG INVENTORY—AFFILIATE

LNG inventory and LNG inventory—affiliate are recorded at cost and are subject to lower of cost or market ("LCM") adjustments at the end of each period. LNG inventory—affiliate represents LNG inventory purchased under a related party LNG lease agreement with Cheniere Marketing, LLC ("Cheniere Marketing"), a wholly owned subsidiary of Cheniere, as described in Note 13—"Related Party Transactions". 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, 2012 and 2011, we had $2.6 million and $0.5 million, respectively, of LNG inventory on our Consolidated Balance Sheets. During the years ended December 31, 2012, 2011 and 2010, we recognized $9.4 million, $0.4 million and $0.3 million, respectively, as a result of LCM adjustments to our LNG inventory.

As of December 31, 2012 and 2011, we had $4.4 million of LNG inventory—affiliate on our Consolidated Balance Sheets. During the years ended December 31, 2012 and 2011 and 2010, we recognized $11.0 million,$10.6 million and zero, respectively, as a result of LCM adjustments to our LNG inventory—affiliate.

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NOTE 6—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of LNG terminal costs and fixed assets, as follows (in thousands):

	December 31,
	2012			2011
LNG terminal costs
LNG terminal	$	1,641,722		$	1,637,724
LNG terminal construction-in-process	1,228,647			286
LNG site and related costs, net	156			163
Accumulated depreciation	(166,538		)	(124,409		)
Total LNG terminal costs, net	2,703,987			1,513,764
Fixed assets
Computer and office equipment	368			227
Vehicles	704			416
Machinery and equipment	1,473			1,068
Other	760			916
Accumulated depreciation	(2,397		)	(1,975		)
Total fixed assets, net	908			652
Property, plant and equipment, net	$	2,704,895		$	1,514,416

Depreciation expense related to the Sabine Pass LNG terminal totaled $42.1 million, $42.6 million and $41.8 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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
Others	15-30

In June 2012, Train 1 and Train 2 of the Liquefaction Project satisfied the criteria for capitalization. Accordingly, costs associated with the construction of Train 1 and Train 2 of the Liquefaction Project have been recorded as construction-in-process since that date. For the year ended December 31, 2012, we capitalized $35.1 million of interest expense related to the construction of Train 1 and Train 2 of the Liquefaction Project.

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NOTE 7—DEBT ISSUANCE COSTS

We have incurred debt issuance costs in connection with our long-term debt. These costs are capitalized and are being amortized over the term of the related debt. The amortization of debt issuance costs associated with the 2016 Notes and 2020 Notes was recorded as interest expense. The amortization of the debt issuance costs associated with the Liquefaction Credit Facility for the construction of Train 1 and Train 2 of the Liquefaction Project was capitalized. As of December 31, 2012, we had capitalized $220.9 million of costs directly associated with the arrangement of debt financing, net of accumulated amortization, as follows (in thousands): 

Long-Term Debt	Debt Issuance Costs		Amortization Period	Accumulated Amortization			Net Costs
Liquefaction Credit Facility	$	212,795	7 years	$	(12,728	)	$	200,067
2016 Notes	30,057		10 years	(18,030		)	12,027
2020 Notes	9,092		8 years	(237		)	8,855
Total	$	251,944		$	(30,995	)	$	220,949

NOTE 8—FINANCIAL INSTRUMENTS

Derivative Instruments

We have entered into certain instruments to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory ("LNG Inventory Derivatives"), to hedge the exposure to 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 volatility in a portion of the floating-rate interest payments under the Liquefaction Credit Facility ("Interest Rate Derivatives").

The following table (in thousands) shows the fair value of our derivative assets and liabilities that are required to be measured at fair value on a recurring basis as of December 31, 2012 and 2011, which are classified as other current assets, other current liabilities and other non-current liabilities in our Consolidated Balance Sheets.

	Fair Value Measurements as of
	December 31, 2012								December 31, 2011
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
LNG Inventory Derivatives asset	$	—	$	232	$	—	$	232	$	—	$	1,610	$	—	$	1,610
Fuel Derivatives liability	—		98		—		98		—		1,415		—		1,415
Interest Rate Derivatives liability	—		26,424		—		26,424		—		—		—		—

The estimated fair values of our LNG Inventory Derivatives and Fuel Derivatives are the amount at which the instruments could be exchanged currently between willing parties. We value these derivatives using observable commodity price curves and other relevant data. We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.

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Commodity Derivatives

Changes in the fair value of our LNG Inventory Derivatives and Fuel Derivatives 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 following table (in thousands) shows the fair value and location of our LNG Inventory Derivatives and Fuel Derivatives on our Consolidated Balance Sheets:

		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2012		December 31, 2011
LNG Inventory Derivatives asset	Prepaid expenses and other	$	232	$	1,610
Fuel Derivatives liability	Other current liabilities	98		1,415

The following table (in thousands) shows the changes in the fair value and settlements of our LNG Inventory Derivatives recorded in marketing and trading revenues (losses) on our Consolidated Statements of Operations during the years endedDecember 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
LNG Inventory Derivatives gain	$	1,036	$	2,300	$	—

The following table (in thousands) shows the changes in the fair value and settlements of our Fuel Derivatives recorded in derivative gain (loss) on our Consolidated Statements of Operations during the years endedDecember 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
Fuel Derivatives gain (loss)	$	(622	)	$	(2,251	)	$	461

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions.  Collateral of $0.9 million and $0.8 million deposited for such contracts, which has not been reflected in the derivative fair value tables, is included in the other current assets balance as of December 31, 2012, and 2011, respectively.

Interest Rate Swaps Designated as Cash Flow Hedges

In August 2012, Sabine Pass Liquefaction entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the Liquefaction Credit Facility.

Sabine Pass Liquefaction has elected to designate these Interest Rate Derivatives as hedging instruments which is required in order to qualify for cash flow hedge accounting. As a result of this cash flow hedge designation, we recognize the Interest Rate Derivatives as an asset or liability at fair value, and reflect changes in fair value through other comprehensive income in our Consolidated Statements of Comprehensive Loss. Any hedge ineffectiveness associated with the Interest Rate Derivatives is recorded immediately as derivative gain (loss) in our Consolidated Statements of Operations. The realized gain (loss) on the Interest Rate Derivatives is recorded as an (increase) decrease in interest expense on our Consolidated Statements of Operations to the extent not capitalized as part of the Liquefaction Project. The effective portion of the gains or losses on our Interest Rate Derivatives recorded in other comprehensive income is reclassified to earnings as interest payments on the Liquefaction Credit Facility impact earnings. In addition, amounts recorded in other comprehensive income are also reclassified into earnings if it becomes probable that the hedged forecasted transaction will not occur.

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The Interest Rate Derivatives hedge approximately 75% of the weighted average of the expected outstanding borrowings over the term of the Liquefaction Credit Facility. The aggregate notional amount each month follows our expected borrowing schedule under the Liquefaction Credit Facility with an expected maximum swap notional amount outstanding of $2.9 billion in 2017. Based on the continued development of our financing strategy for the Liquefaction Project, in particular the fixed-rate debt as described in Note 18—"Subsequent Events", during the fourth quarter of 2012 we determined it was no longer probable that a portion of the forecasted variable interest payments on the Liquefaction Credit Facility would occur in the time period originally specified. As a result, a portion of the Interest Rate Derivatives were no longer effective hedges and the hedge relationships for this portion were de-designated as of October 1, 2012. Fair value adjustments on this de-designated portion of the Interest Rate Derivatives subsequent to October 1, 2012 are recorded within the Consolidated Statements of Operations. We have continued to maintain the Interest Rate Derivatives (both designated and de-designated) in anticipation of our upcoming financing needs, particularly for the financing of the construction of Train 3 and Train 4 of the Liquefaction Project, and have concluded that the likelihood of occurrence of our variable interest payments has not changed to probable not to occur. As a result, amounts recorded in other comprehensive income related to our designated and de-designated Interest Rate Derivatives will continue to remain in other comprehensive income until interest payments on the Liquefaction Credit Facility impact earnings.

At December 31, 2012, Sabine Pass Liquefaction had the following Interest Rate Derivatives outstanding that converted $20.0 million of the Liquefaction Credit Facility from a variable to a fixed interest rate. Sabine Pass Liquefaction pays a fixed interest rate on the swap and in exchange receives a variable interest rate based on the one-month LIBOR.

	Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
Interest Rate Derivatives - Designated	$16.1 million	$2.3 billion	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR
Interest Rate Derivatives - De-designated	$3.9 million	$575.3 million	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR

Interest Rate Derivatives were reflected in our Consolidated Balance Sheets at fair value with the effective portion of the Interest Rate Derivatives' gain or loss recorded in other comprehensive income. Fair value adjustments subsequent to October 1, 2012 on the de-designated portion of the Interest Rate Derivatives were recorded within the Consolidated Statements of Operations. The following table (in thousands) shows the fair value of our interest rate swaps:

		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2012		December 31, 2011
Interest Rate Derivatives - Designated	Non-current derivative liabilities	$	21,290	$	—
Interest Rate Derivatives - De-designated	Non-current derivative liabilities	5,134		—

The following table (in thousands) shows our Interest Rate Derivatives market adjustments recorded during the year endedDecember 31, 2012:

	Gain (Loss) in Other Comprehensive Income					Gain (Loss) Reclassified from Accumulated OCI into Interest Expense (Effective Portion)				Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	2012			2011		2012		2011		2012		2011
Interest Rate Derivatives - Designated	$	(21,290	)	$	—	$	—	$	—	$	—	$	—
Interest Rate Derivatives - De-designated	(5,814		)	—		—		—		—		—
Interest Rate Derivatives - Settlements	(136		)	—		—		—		—		—

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The following table (in thousands) shows the changes in the fair value of our De-designated Interest Rate Derivatives recorded in derivative gain on our Consolidated Statements of Operations during the years endedDecember 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
Interest Rate Derivatives - De-designated	$	679	$	—	$	—

Balance Sheet Presentation

The Company's commodity and interest rate derivatives are presented on a net basis on our Consolidated Balance Sheets as described above. The following table (in thousands) shows the fair value of our derivatives outstanding on a gross basis:

	December 31, 2012		December 31, 2011
Commodity Derivatives:
Assets	$	607	$	1,942
Liabilities	474		1,747
Interest Rate Derivatives:
Assets - designated	$	17,512	$	—
Assets - de-designated	4,283		—
Liabilities - designated	38,729		—
Liabilities - de-designated	9,491		—

Other Financial Instruments

The estimated fair value of our other 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.

Other Financial Instruments (in thousands):

	December 31, 2012				December 31, 2011
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2013 Notes (1)	$	—	$	—	$	550,000	$	555,500
2016 Notes, net of discount (1)	1,647,113		1,824,177		1,642,418		1,650,630
2020 Notes (1)	420,000		437,850		—		—
Liquefaction Credit Facility (2)	100,000		100,000		—		—

(1) The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on December 31, 2012 and 2011, as applicable.

(2) The Level 3 estimated fair value of the Liquefaction Credit Facility as of December 31, 2012 was determined to be the carrying amount due to our ability to call this debt at anytime without penalty. 

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NOTE 9—ACCRUED LIABILITIES

As of December 31, 2012 and 2011, accrued liabilities consisted of the following (in thousands):

	December 31,
	2012		2011
Interest and related debt fees	$	16,327	$	13,732
Affiliate	5,791		3,794
LNG liquefaction costs	26,131		1,635
LNG terminal costs	977		1,122
Other	3,968		262
Total accrued liabilities (including affiliate)	$	53,194	$	20,545

NOTE 10—DEFERRED REVENUE

Advance Capacity Reservation Fee

In November 2004, Total Gas & 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.

As of December 31, 2012, we had recorded $4.0 million and $21.5 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, 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.

TUA Payments

Following the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008, Sabine Pass LNG began receiving capacity reservation fee payments from Cheniere Marketing under its TUA. Effective July 1, 2010, Cheniere Marketing assigned its existing TUA with Sabine Pass LNG to Cheniere Investments, including all of its rights, titles, interests, obligations and liabilities in and under the TUA. After the assignment of the TUA from Cheniere Marketing to Cheniere Investments, Cheniere Investments began making its TUA payments on a monthly basis. Sabine Pass Liquefaction obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, Sabine Pass LNG, Sabine Pass Liquefaction and Cheniere Investments entered into a terminal use rights assignment and agreement ("TURA") pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to Sabine Pass LNG. We have guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA. However, the revenue earned by Sabine Pass LNG from Cheniere Investments' capacity payments under its TUA was eliminated and under its TURA is eliminated upon consolidation of our financial statements. As a

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result, we have zero current deferred revenue—affiliate related to Cheniere Investments' monthly advance capacity reservation fee payment as of December 31, 2012 and 2011.

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, 2012 and 2011, we had recorded $21.1 million as current deferred revenue on our Consolidated Balance Sheets related to Total's and Chevron's monthly TUA payments.

Cooperative Endeavor Agreements

In July 2007, Sabine Pass LNG executed Cooperative Endeavor Agreements ("CEAs") with various Cameron Parish, Louisiana taxing authorities that allow them to accelerate certain of its property tax payments scheduled to begin in 2019. This ten-year initiative represents an aggregate $25.0 million commitment, and will make resources available to the Cameron Parish taxing authorities on an accelerated basis in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for Sabine Pass LNG’s advance payments of ad valorem taxes, Cameron Parish will grant Sabine Pass LNG a dollar for dollar credit against future ad valorem taxes to be levied against its LNG terminal starting in 2019. In September 2007, Sabine Pass LNG entered into an agreement with Cheniere Marketing, pursuant to which Cheniere Marketing will advance it any and all amounts payable under the CEAs in exchange for a similar amount of credits against future ad valorem reimbursements it would owe to Sabine Pass LNG under its TUA starting in 2019. These advance ad valorem tax payments were recorded to other assets, and payments from Cheniere Marketing that Sabine Pass LNG utilized to make the early payment of taxes were recorded as deferred revenue. As of December 31, 2012 and 2011, we had $14.7 million and $12.3 million, respectively, of other non-current assets and non-current deferred revenue resulting from accelerated ad valorem tax payments.

NOTE 11—LONG-TERM DEBT

As of December 31, 2012 and 2011, our long-term debt consisted of the following (in thousands):

	December 31,
	2012			2011
Long-term debt
2013 Notes	$	—		$	550,000
2016 Notes	1,665,500			1,665,500
2020 Notes	420,000			—
Liquefaction Credit Facility	100,000			—
Total long-term, debt	2,185,500			2,215,500
Long-term debt discount
2016 Notes	(18,387		)	(23,082		)
Total long-term debt, net of discount	$	2,167,113		$	2,192,418

Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2012 (in thousands): 

	Payments Due for the Years Ended December 31,
	Total		2013		2014 to 2015		2016 to 2017		Thereafter
Debt (including related parties):
2016 Notes	$	1,665,500	$	—	$	—	$	1,665,500	$	—
2020 Notes	420,000		—		—		—		420,000
Liquefaction Credit Facility	100,000		—		—		—		100,000
Debt (including related parties)	$	2,185,500	$	—	$	—	$	1,665,500	$	520,000

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Senior Notes

In November 2006, Sabine Pass LNG issued an aggregate principal amount of $2,032.0 million of Senior Secured Notes, consisting of $550.0 million of 7.25% Senior Secured Notes due 2013 (the "2013 Notes") and $1,482.0 million of 7.50% Senior Secured Notes due 2016 (the "2016 Notes"). 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. In October 2012, Sabine Pass LNG issued an aggregate principal amount of $420.0 million of 6.50% Senior Secured Notes due in 2020 (the "2020 Notes"), whose terms were substantially similar to the outstanding 2016 Notes, and redeemed all of the 2013 Notes. As a result, we recorded a $42.6 million loss on early extinguishment of debt primarily related to make-whole payments. Collectively, the 2013 Notes, 2016 Notes, and 2020 Notes are referred to as the "Senior Notes." Interest on the 2016 Notes is payable semi-annually in arrears on May 30 and November 30 of each year. Interest on the 2020 Notes is payable semi-annually in arrears on May 1 and November 1 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 its 2016 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 2016 Notes; or

• the excess of: a) the present value at such redemption date of (i) the redemption price of the 2016 Notes plus (ii) all required interest payments due on the 2016 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 2016 Notes, if greater.

Sabine Pass LNG may redeem all or part of its 2020 Notes at any time on or after November 1, 2016, at fixed redemption prices specified in the Indenture, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also, at its option, redeem all or part of the 2020 Notes at any time prior to November 1, 2016, at a "make-whole" price set forth in the Indenture, plus accrued and unpaid interest, if any, to the date of redemption.

Under the indentures governing the Senior Notes, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. 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 indenture. During the years ended December 31, 2012, 2011 and 2010, Sabine Pass LNG made distributions of $333.5 million, $313.6 million and $374.8 million, respectively, after satisfying all the applicable conditions in the indenture.

In connection with the issuance of the 2020 Notes, Sabine Pass LNG also entered into a registration rights agreement (the "Registration Rights Agreement"). Under the Registration Rights Agreement, Sabine Pass LNG has agreed to use reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange the notes for an issue of SEC-registered notes with terms substantially identical to the 2020 Notes within 360 days after the 2020 Notes were issued. In certain circumstances, Sabine Pass LNG may be required to file a shelf registration statement to cover resales of the 2020 Notes. If Sabine Pass LNG fails to satisfy these obligations, Sabine Pass LNG may be required to pay additional interest to holders of the 2020 Notes under certain circumstances.

Liquefaction Credit Facility

In July 2012, Sabine Pass Liquefaction entered into the $3.6 billion Liquefaction Credit Facility with a syndicate of lenders. The Liquefaction Credit Facility will be used to fund a portion of the costs of developing, constructing and placing into operation Train 1 and Train 2 of the Liquefaction Project. The Liquefaction Credit Facility will mature on the earlier of July 31, 2019 or the second anniversary of the completion date of Train 1 and Train 2 of the Liquefaction Project, as defined in the Liquefaction Credit Facility. Borrowings under the Liquefaction Credit Facility may be refinanced, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. Sabine Pass Liquefaction made a $100.0 million

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borrowing under the Liquefaction Credit Facility in August 2012 after meeting the required conditions precedent to the initial advance.

Borrowings under the Liquefaction Credit Facility bear interest, at Sabine Pass Liquefaction's election, at a variable rate equal to LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans is 3.50% during construction and 3.75% during operations, and the applicable margin for base rate loans is 2.50% during construction and 2.75% during operations. Interest on LIBOR loans is due and payable at the end of each LIBOR period, and interest on base rate loans is due and payable at the end of each calendar quarter. The Liquefaction Credit Facility required Sabine Pass Liquefaction to pay certain up-front fees to the agents and lenders in the aggregate amount of approximately $178 million and provides for a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of the undrawn commitment. Annual administrative fees must also be paid to the agent and the trustee. The principal of loans made under the Liquefaction Credit Facility must be repaid in quarterly installments, commencing with the first calendar quarter ending at least three months following the completion of Train 1 and Train 2 of the Liquefaction Project. Scheduled repayments are based upon an 18-year amortization, with the remaining balance due upon the maturity of the Liquefaction Credit Facility.

Under the terms and conditions of the Liquefaction Credit Facility, all cash held by Sabine Pass Liquefaction is controlled by the collateral agent. These funds can only be released by the collateral agent upon satisfaction of certain terms and conditions, including receipt of satisfactory documentation that the Liquefaction Project costs are bona fide expenditures and are permitted under the terms of the Liquefaction Credit Facility. The Liquefaction Credit Facility does not permit Sabine Pass Liquefaction to hold any cash, or cash equivalents, outside of the accounts established under the agreement. Because these cash accounts are controlled by the collateral agent, the cash balance of $100.0 million held in these accounts as of December 31, 2012 is classified as restricted on our Consolidated Balance Sheets.

The Liquefaction Credit Facility contains customary conditions precedent for the second borrowing and any subsequent borrowings, as well as customary affirmative and negative covenants. The obligations of Sabine Pass Liquefaction under the Liquefaction Credit Facility are secured by substantially all of the assets of Sabine Pass Liquefaction as well as all of the membership interests in Sabine Pass Liquefaction, and a security interest in Cheniere Partners' rights under the Blackstone Unit Purchase Agreement and the guaranty related thereto.

Under the terms of the Liquefaction Credit Facility, Sabine Pass Liquefaction is required to hedge against the potential of rising interest rates with respect to no less than 75% (calculated on a weighted average basis) of the projected outstanding borrowings. In connection with the closing of the Liquefaction Credit Facility, Sabine Pass Liquefaction entered into interest rate swap agreements. The swap agreements have the effect of fixing the LIBOR component of the interest rate payable under the Liquefaction Credit Facility with respect to forecasted borrowings under the Liquefaction Credit Facility up to a maximum of $2.9 billion at 1.98% from August 14, 2012 to July 31, 2019, the final termination date of the swap agreements.

NOTE 12—DESCRIPTION OF EQUITY INTERESTS

The common units, Class B units and subordinated units represent limited partner interests in us. The holders of the units are entitled to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. On May 31, 2007, Cheniere LNG Holdings, LLC contributed all of its 135,383,831 subordinated units to Cheniere Subsidiary Holdings, LLC.

The common units have the right to receive minimum quarterly distributions of $0.425, plus any arrearages thereon, before any distribution is made to the holders of the subordinated units. Subordinated units will convert into common units on a one-for-one basis when we meet financial tests specified in the partnership agreement. Although common and subordinated unitholders are not obligated to fund losses of the partnership, their capital accounts, which would be considered in allocating the net assets of the partnership were it to be liquidated, continue to share in losses.

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights, which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus after the minimum distributions have been achieved and as additional target levels are met. The higher percentages range from 15% up to 50%.

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In January 2011, we 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 the Liquefaction Project. During the year ended December 31, 2011, we sold 0.5 million common units with net proceeds of $9.0 million. During the year endedDecember 31, 2012, we sold 0.5 million common units in connection with the at-the-market program with net proceeds of $11.1 million. We paid $0.3 million in commissions to Miller Tabak + Co., Inc., as sales agent, in connection with the at-the-market program during the year endedDecember 31, 2012.

In September 2011, we 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. We received net proceeds of approximately $60 million that we are using for general business purposes, including development costs associated with the Liquefaction Project. In September 2012, we sold 8.0 million common units in an underwritten public offering at a price of $25.07 per common unit. We received net proceeds of $194.0 million that were used for partial repayment of Sabine Pass LNG's 2013 Notes, and, to the extent not so used, for general business purposes.

During the year ended December 31, 2011, we also received $1.5 million in net proceeds from our general partner in connection with the exercise of its right to maintain its 2% ownership interest in us. We received $45.1 million in net proceeds from our general partner in connection with the exercise of its right to maintain its 2% ownership interest in us during the year endedDecember 31, 2012.

In May 2012, we and Blackstone CQP Holdco LP ("Blackstone") entered into a unit purchase agreement (the "Blackstone Unit Purchase Agreement") .  Under the Blackstone Purchase Unit Agreement, Blackstone agreed to purchase $1.5 billion of newly issued Cheniere Partners Class B units ("Class B units") from us in a private placement.  In May 2012, Cheniere also entered into a unit purchase agreement with us (the "Cheniere Unit Purchase Agreeement"). Under the Cheniere Unit Purchase Agreement, Cheniere agreed to purchase $500.0 million of newly issued Class B units. During the year endedDecember 31, 2012, Blackstone and Cheniere completed their acquisitions of 100.0 million and 33.3 million Class B units, respectively, under their unit purchase agreements for total consideration of $1.5 billion and $500.0 million, respectively. Proceeds from the financings are being used to fund the equity portion of the costs of developing, constructing and placing into service the Liquefaction Project. 

The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basis beginning on the initial purchase of the Class B units, and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The Class B units are not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale of substantially all of our assets). The holders of Class B units have a preference over the holders of the subordinated units in the event of a liquidation (or merger, combination or sale of substantially all of our assets). The Class B units will mandatorily convert into common units upon the earlier of the substantial completion date of Train 3 or August 9. 2017, provided that if Train 3 notice to proceed with construction is issued prior to August 9. 2017, then the mandatory conversion date becomes the substantial completion date of Train 3.

NOTE 13—RELATED PARTY TRANSACTIONS

As of December 31, 2012 and 2011, we had $5.0 million and $0.7 million of advances to affiliates, respectively. In addition, we have entered into the following related party transactions:

LNG Terminal Capacity Agreements

Terminal Use Agreement

In November 2006, Cheniere Marketing, LLC, a wholly owned subsidiary of Cheniere ("Cheniere Marketing"), reserved approximately 2.0 Bcf/d of regasification capacity under a firm commitment terminal use agreement ("TUA") with Sabine Pass LNG and was required to make capacity reservation fee payments aggregating approximately $250 million per year for the period from January 1, 2009, through at least September 30, 2028. Cheniere guaranteed Cheniere Marketing's obligations under its TUA.

Effective July 1, 2010, Cheniere Marketing assigned its existing TUA with Sabine Pass LNG to Cheniere Investments, our wholly owned subsidiary, including all of its rights, titles, interests, obligations and liabilities in and under the TUA. After the assignment of the TUA from Cheniere Marketing to Cheniere Investments, Cheniere Investments began making its TUA payments on a monthly basis. Sabine Pass Liquefaction obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere

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Investments of its rights, title and interest under its TUA. In connection with the assignment, Sabine Pass LNG, Sabine Pass Liquefaction and Cheniere Investments entered into a terminal use rights assignment and agreement ("TURA") pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to Sabine Pass LNG. We have guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA. However, the revenue earned by Sabine Pass LNG from Cheniere Investments' capacity payments under its TUA was eliminated and under its TURA is eliminated upon consolidation of our financial statements.

In connection with monetizing Cheniere Investments’ reserved capacity under its TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into a variable capacity rights agreement ("VCRA") pursuant to which 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 increase our 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 its subordinated units. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs paid by Cheniere Investments under the TURA. We recorded $4.9 million, $11.2 million and $1.9 million of revenues—affiliate from Cheniere Marketing in the years endedDecember 31, 2012, 2011, and 2010, respectively, related to the VCRA.

In September 2012, Sabine Pass Liquefaction entered into a partial TUA assignment agreement with Total, whereby Sabine Pass Liquefaction will progressively gain access to Total's capacity and other services provided under Total's TUA with Sabine Pass LNG.  This agreement will provide Sabine Pass Liquefaction with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Train 5 and Train 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of Train 3, and permit Sabine Pass Liquefaction to more flexibly manage its storage with the commencement of Train 1. Notwithstanding any arrangements between Total and Sabine Pass Liquefaction, payments required to be made by Total to Sabine Pass LNG shall continue to be made by Total to Sabine Pass LNG in accordance with its TUA.

LNG Sale and Purchase Agreement ("SPA")

Cheniere Marketing has entered into an SPA with Sabine Pass Liquefaction to purchase, at its option, any excess LNG produced that is not committed to non-affiliate parties, for up to a maximum of 104,000,000 MMBtu per annum produced from Train 1 through Train 4 of the Liquefaction Project. Cheniere Marketing may purchase incremental LNG volumes at a price of 115% of Henry Hub plus up to $3.00 per MMBtu for the first 36,000,000 MMBtu of the most profitable cargoes sold each year by Cheniere Marketing, and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing.

LNG Lease Agreement

In September 2011, Cheniere Investments entered into an agreement in the form of a lease (the "LNG Lease Agreement")with Cheniere Marketing that enables Cheniere Investments to supply the Sabine Pass LNG terminal with LNG to maintain proper LNG inventory levels and temperature. The LNG Lease Agreement also enables Cheniere Investments to hedge the exposure to variability in expected future cash flows of its LNG inventory. Under the terms of the LNG Lease Agreement, Cheniere Marketing funds all activities related to the purchase and hedging of the LNG, and Cheniere Investments reimburses Cheniere Marketing for all costs and assumes full price risk associated with these activities.

As a result of Cheniere Investments assuming full price risk associated with the LNG Lease Agreement, LNG inventory purchased by Cheniere Marketing under this arrangement is classified as LNG inventory—affiliate on our Consolidated Balance Sheets, and is recorded at cost and subject to lower-of-cost-or-market ("LCM") adjustments at the end of each period. LNG inventory—affiliate cost is determined using the average cost method. Recoveries of losses resulting from interim period LCM adjustments are made due to market price recoveries on the same LNG inventory—affiliate in the same fiscal year and are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. Gains or losses on the sale of LNG inventory—affiliate and LCM adjustments are recorded as revenues on our Consolidated Statements of Operations. As of December 31, 2012, we had 1,369,000 MMBtu of LNG inventory—affiliate recorded at $4.4 million on our Consolidated Balance Sheets, and as of December 31, 2011, we had 1,527,000 MMBtu of LNG inventory—affiliate recorded at $4.4 million on our

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Consolidated Balance Sheets. During the years endedDecember 31, 2012 and 2011, we recognized a loss of $1.4 million and $11.4 million, respectively, as a result of LCM adjustments to our LNG inventory—affiliate.

Cheniere Marketing has entered into financial derivatives, on our behalf, to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory under the LNG Lease Agreement. The fair value of these derivative instruments at December 31, 2012 and 2011 was $0.2 million and $1.6 million, respectively, and was classified as other current assets on our Consolidated Balance Sheets. Changes in the fair value of these derivative instruments are classified as revenues on our Consolidated Statements of Operations. We recorded revenues of $1.0 million and $2.3 million related to LNG inventory—affiliate derivatives in the years endedDecember 31, 2012 and 2011, respectively.

Service Agreements

During the years endedDecember 31, 2012, 2011 and 2010, we recorded general and administrative expense—affiliate of $53.5 million, $19.0 million and $15.9 million, respectively, under the following service agreements.

Cheniere Partners Services Agreement

We have entered into a services agreement with Cheniere LNG Terminals, Inc. ("Cheniere Terminals"), a wholly owned subsidiary of Cheniere, pursuant to which we pay Cheniere Terminals a quarterly non-accountable overhead reimbursement charge of $2.8 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, we reimburse Cheniere Terminals for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Sabine Pass LNG O&M Agreement

Sabine Pass LNG has entered into a long-term operation and maintenance agreement (the "Sabine Pass LNG O&M Agreement") with a wholly owned subsidiary of Cheniere pursuant to which we receive all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. Sabine Pass LNG is required to pay a fixed monthly fee of $130,000 (indexed for inflation) under the agreement, and the counterparty is entitled to a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between Sabine Pass LNG and the counterparty at the beginning of each operating year. In addition, Sabine Pass LNG is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses.

Sabine Pass LNG MSA

Sabine Pass LNG has entered into a long-term management services agreement (the "Sabine Pass LNG MSA") with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters provided for under the O&M Agreement. Sabine Pass LNG is required to pay Cheniere Terminals a monthly fixed fee of $520,000 (indexed for inflation).

Sabine Pass Liquefaction O&M Agreement

In May 2012, Sabine Pass Liquefaction entered into an operation and maintenance agreement (the "Liquefaction O&M Agreement") with a wholly owned subsidiary of Cheniere and our general partner pursuant to which we receive all of the necessary services required to construct, operate and maintain the liquefaction facilities. Before the liquefaction facilities are operational, the services to be provided include, among other services, obtaining governmental approvals on behalf of Sabine Pass Liquefaction, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After the liquefaction facilities are operational, the services include all necessary services required to operate and maintain the liquefaction facilities.

Before the liquefaction facilities are operational, in addition to reimbursement of operating expenses, Sabine Pass Liquefaction is required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the liquefaction facilities are operational, Sabine Pass

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Liquefaction will pay in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to such Train.

Sabine Pass Liquefaction MSA

In May 2012, Sabine Pass Liquefaction entered into a management services agreement (the "Liquefaction MSA") with a wholly owned subsidiary of Cheniere pursuant to which such subsidiary was appointed to manage the construction and operation of the liquefaction facilities, excluding those matters provided for under the Liquefaction O&M Agreement. The services to be provided include, among other services, exercising the day-to-day management of Sabine Pass Liquefaction's affairs and business, managing Sabine Pass Liquefaction's regulatory matters, managing bank and brokerage accounts and financial books and records of Sabine Pass Liquefaction's business and operations, and providing contract administration services for all contracts associated with the liquefaction facilities. Sabine Pass Liquefaction will pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, Sabine Pass Liquefaction pays a fixed monthly fee of $541,667 for services with respect to such Train.

Agreement to Fund Sabine Pass LNG's Cooperative Endeavor Agreements

In July 2007, Sabine Pass LNG executed Cooperative Endeavor Agreements ("CEAs") with various Cameron Parish, Louisiana taxing authorities that allow them to collect certain annual property tax payments from Sabine Pass LNG in 2007 through 2016. This ten-year initiative represents an aggregate $25.0 million commitment and will make resources available to the Cameron Parish taxing authorities on an accelerated basis in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for Sabine Pass LNG's payments of annual ad valorem taxes, Cameron Parish will grant Sabine Pass LNG a dollar for dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. In September 2007, Sabine Pass LNG modified its TUA with Cheniere Marketing, pursuant to which Cheniere Marketing would pay Sabine Pass LNG additional TUA revenues equal to any and all amounts payable under the CEAs in exchange for a similar amount of credits against future TUA payments it would owe Sabine Pass LNG under its TUA starting in 2019. In June 2010, Cheniere Marketing assigned its existing TUA to Cheniere Investments and concurrently entered into a VCRA, allowing Cheniere Marketing to monetize Cheniere Investments' capacity under the TUA after the assignment. In July 2012, Cheniere Investments entered into an amended and restated VCRA with Cheniere Marketing in order for Cheniere Investments to monetize the capacity rights granted under the TURA during construction of the Liquefaction Project. The amended and restated VCRA provides that Cheniere Marketing will continue to fund the CEAs during the term of the amended and restated VCRA and, in exchange, Cheniere Marketing will receive any future credits.

On a consolidated basis, these TUA payments were recorded to other assets, and payments from Cheniere Marketing that Sabine Pass LNG utilized to make the ad valorem tax payments were recorded as deferred revenue. As of December 31, 2012 and 2011, we had $14.7 million and $12.3 million of other non-current assets and non-current deferred revenue resulting from Sabine Pass LNG's ad valorem tax payments and the advance TUA payments received from Cheniere Marketing, respectively.

Contracts for Sale and Purchase of Natural Gas and LNG

Sabine Pass LNG is able to sell and purchase natural gas and LNG under an agreement with Cheniere Marketing. Under this agreement, Sabine Pass LNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase cost paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing in respect of the receipt, purchase, and delivery of the natural gas or LNG to the Sabine Pass LNG terminal.

Sabine Pass LNG recorded $2.8 million, $4.2 million and $2.8 million of natural gas and LNG purchased from Cheniere Marketing under this agreement in the years endedDecember 31, 2012, 2011 and 2010, respectively. Sabine Pass LNG recorded $2.8 million, zero and zero of natural gas sold to Cheniere Marketing under this agreement in the year ended the December 31, 2012, 2011 and 2010, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

LNG Terminal Export Agreement

In January 2010, Sabine Pass LNG and Cheniere Marketing entered into an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  Sabine Pass LNG recorded revenues—affiliate of $0.3 million, $0.3 million and $0.9 million pursuant to this agreement in the years endedDecember 31, 2012, 2011 and 2010, respectively.

Tug Boat Lease Sharing Agreement

In connection with its tug boat lease, Sabine Pass Tug Services, LLC, a wholly owned subsidiary of Sabine Pass LNG ("Tug Services"), entered into a tug sharing agreement with Cheniere Marketing to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. Tug Services recorded revenues—affiliate from Cheniere Marketing of $2.8 million, $2.7 million and $2.7 million pursuant to this agreement in the years endedDecember 31, 2012, 2011 and 2010, respectively.

NOTE 14—LEASES

During the years ended December 31, 2012, 2011 and 2010, we recognized rental expense for all operating leases of $10.0 million, $9.2 million and $9.1 million, respectively.

The following is a schedule by years of future minimum rental payments, excluding inflationary adjustments, required as of December 31, 2012 under the land leases and tug boat lease described below (in thousands):

Year ending December 31,	Lease Payments (2)
2013	$	9,625
2014	9,625
2015	9,604
2016	9,577
2017	9,462
Later years (1)	231,884
Total minimum payments required	$	279,777

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

(2) Lease payments for Sabine Pass LNG’s tug boat lease represent its lease payment obligation and do not take into account the $112.8 million of sublease payments Sabine Pass LNG will receive from its three TUA customers that effectively offset these lease payment obligations, as discussed below.

Land Leases

In January 2005, Sabine Pass LNG exercised its 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 six10-year extensions with similar terms as the initial term. In February 2005, two of the three leases were amended, increasing the total acreage under lease to 853 acres and increasing the annual lease payments to $1.5 million.  In July 2012, Sabine Pass LNG entered into an additional land lease, thereby increasing the total acreage under lease to 883 acres.  The annual lease payments are adjusted for inflation every 5 years based on a consumer price index, as defined in the lease agreements.

In November 2011, Sabine Pass Liquefaction entered into a land lease of 80.7 acres to be used as the laydown area during the construction of the Liquefaction Project. The annual lease payment is $138,000. The lease has an initial term of five years, with options to renew for five1-year extensions with similar terms as the initial term. In December 2011, Sabine Pass Liquefaction entered into a land lease of 80.6 acres to be used for the site of the Liquefaction Project. The annual lease payment is $257,800. The lease has an initial term of 30 years, with options to renew for six10-year extensions with similar terms as the initial term. The annual lease payment is adjusted for inflation every 5 years based on a consumer price index, as defined in the lease agreement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

We recognized $2.3 million, $1.8 million and $1.7 million of site lease expense on our Consolidated Statements of Operations in 2012, 2011 and 2010, respectively.

Tug Boat Lease

In the second quarter of 2008, Sabine Pass LNG acquired a lease for the use of tug boats and marine services at the Sabine Pass LNG terminal as a result of its purchase of Tug Services (the "Tug Agreement").  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 5 years each.  We have determined that the Tug Agreement contains a lease for the tugs specified in the Tug Agreement.  In addition, we have concluded that the tug lease contained in the Tug Agreement is an operating lease, and as such, the equipment component of the Tug Agreement will be charged to expense over the term of the Tug Agreement as it becomes payable.

In connection with this lease acquisition, Tug Services entered into a Tug Sharing Agreement with Chevron, Total and Cheniere Marketing to provide their LNG cargo vessels with tug boat and marine services at our LNG terminal and effectively offset the cost of our lease. The Tug Sharing Agreement provides for each of our customers to pay Tug Services an annual service fee.

NOTE 15—COMMITMENTS AND CONTINGENCIES

LNG Commitments

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.

Bechtel EPC Contract

Sabine Pass Liquefaction has entered into lump sum turnkey contracts for the engineering, procurement and construction of Train 1 and Train 2 (the "EPC Contract (Train 1 and 2)") and Train 3 and Train 4 (the "EPC Contract (Train 3 and 4)", and together with the EPC Contract (Train 1 and 2), the "EPC Contracts"), with Bechtel in November 2011 and December 2012, respectively.

The EPC Contract (Train 1 and 2) 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 up to $30.0 million depending on the termination date.

The EPC Contract (Train 3 and 4) with Bechtel provides for (i) the procurement, engineering, design, installation, training, commissioning and placing into service of Train 3 and Train 4 and related facilities and (ii) certain modifications and improvements to Train 1, Train 2 and the Sabine Pass LNG terminal. The EPC Contract (Train 3 and 4) provides that Sabine Pass Liquefaction will pay Bechtel a contract price of $3.8 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. If Sabine Pass Liquefaction fails to issue the notice to proceed by December 31, 2013, 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.

Services Agreements

We have entered into certain services agreements with affiliates. See Note 13—"Related Party Transactions" for information regarding such agreements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Public Company Expenses

We and Sabine Pass LNG are reporting entities under the Exchange Act. As a result, our combined total annual general and administrative expenses will include costs related to compliance with the Sarbanes-Oxley Act of 2002, filing annual and quarterly reports with the SEC, increased audit fees, tax compliance and publicly traded partnership tax reporting, investor relations, director compensation, directors’ and officers’ insurance, legal fees, registrar and transfer agent fees and stock exchange fees. Cheniere advanced us funds to pay public company expenses associated with being a publicly traded partnership through 2008, after which time we used available cash to pay such expenses directly and, after payment of the initial quarterly distribution on all units, to reimburse Cheniere.

Crest Royalty

Under a settlement agreement with Crest Energy dated as of June 14, 2001, Cheniere 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 was calculated based on the volume of natural gas processed through covered LNG facilities, subject to a minimum of $2.0 million and a maximum of approximately $11.0 million per production year. In 2003, Freeport LNG contractually assumed the obligation to pay the Crest Royalty for natural gas processed at Freeport LNG's receiving terminal. Subsequently, the calculation of the Crest Royalty and the scope of Freeport LNG's assumed obligation to pay the Crest Royalty became the subject of litigation involving Cheniere, Crest Energy, and Freeport LNG ("Crest Royalty Litigation").

In March 2012, Cheniere purchased all of the rights, title, and interest in the Crest Royalty from Crest Energy. That purchase resulted in Crest Energy's dismissal from the Crest Royalty Litigation. In September 2012, Cheniere entered into a settlement of the remaining claims in the Crest Royalty Litigation with Freeport LNG. As part of the settlement agreement, Cheniere terminated the Crest Royalty. As a result of all of these transactions, Cheniere resolved disputes persisting since 2001 related to real property at Freeport LNG and has released us from the first priority lien that had been granted to holders of the Crest Royalty.

Restricted Net Assets

At December 31, 2012, our restricted net assets of consolidated subsidiaries were approximately $972.4 million.

Other Commitments

State Tax Sharing Agreement

In November 2006, Sabine Pass LNG and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass LNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass LNG will pay to Cheniere an amount equal to the state and local tax that Sabine Pass LNG would be required to pay if Sabine Pass LNG's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass LNG under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass LNG. The agreement is effective for tax returns due on or after January 1, 2008.

In August 2012, Sabine Pass Liquefaction and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass Liquefaction and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass Liquefaction will pay to Cheniere an amount equal to the state and local tax that Sabine Pass Liquefaction would be required to pay if Sabine Pass Liquefaction's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass Liquefaction under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass Liquefaction. The agreement is effective for tax returns due on or after August 2012.

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CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Cooperative Endeavor Agreements ("CEAs")

In July 2007, Sabine Pass LNG executed CEAs with various Cameron Parish, Louisiana taxing authorities. See Note 13—"Related Party Transactions" for information regarding such agreements.

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, 2012, 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.

NOTE 16—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,
	2012		2011		2010
Cash paid during the year for interest, net of amounts capitalized	$	160,273	$	164,513	$	164,793
LNG terminal costs funded with accounts payable and accrued liabilities	99,680		—		—

NOTE 17—Cash Distributions and Net Income (Loss) per Common Unit

Cash Distributions

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Generally, our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from operating surplus as defined in the partnership agreement. The following provides a summary of distributions paid by us during the years ended December 31, 2012, 2011 and 2010:

						Total Distribution (in thousands)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Distribution Per Subordinated Unit		Common Units		Class B Units	Subordinated Units	General Partner Units
November 14, 2012	July 1 - September 30, 2012	$	0.425	$	—	$	16,783	—	—	$	342
August 13, 2012	April 1 - June 30, 2012	0.425		—		13,383		—	—	273
May 14, 2012	January 1 - March 31, 2012	0.425				13,323		—		272
February 12, 2012	October 1 - December 31, 2011	0.425				13,176		—		269
November 14, 2011	July 1 - September 30, 2011	0.425		—		13,176		—	—	269
August 12, 2011	April 1 - June 30, 2011	0.425		—		11,446		—	—	234
May 13, 2011	January 1 - March 31, 2011	0.425		—		11,335		—	—	231
February 11, 2011	October 1 - December 31, 2010	0.425		—		11,229		—	—	229
November 12, 2010	July 1 - September 30, 2010	0.425		—		11,227		—	—	229
August 13, 2010	April 1 - June 30, 2010	0.425		—		11,227		—	—	229
May 14, 2010	January 1 - March 31, 2010	0.425		0.425		11,227		—	57,538	1,403
February 12, 2010	October 1 - December 31, 2009	0.425		0.425		11,227		—	57,538	1,403

The subordinated units will receive distributions only to the extent we have available cash above the minimum quarterly distribution requirement for our common unitholders and general partner and certain reserves.  As a result of the assignment of Cheniere Marketing's TUA to Cheniere Investments, effective July 1, 2010, our available cash for distributions was reduced. Therefore, we have not paid distributions on our subordinated units since the distribution made with respect to the quarter ended March 31, 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Pursuant to the Blackstone and Cheniere Unit Purchase Agreements, we issued and sold 133.3 million Class B units at a price of $15.00 per Class B unit in the year ended ended December 31, 2012, resulting in total gross proceeds of $2.0 billion. The Class B units were issued at a discount to the market price of the common units into which they are convertible.  This discount totaling $1,950.0 million represents a beneficial conversion feature and is reflected as an increase in common and subordinated unitholders’ capital and a decrease in Class B unitholders’ capital to reflect the fair value of the Class B units at issuance on our consolidated statement of partners’ and owners' capital (deficit).  The beneficial conversion feature is considered a dividend that will be distributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders' capital and a decrease in common and subordinated unitholders’ capital.  The impact of the beneficial conversion feature is also included in earnings per unit for the year endedDecember 31, 2012.

Net Income (Loss) per Common Unit

Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. The two class method dictates that net income (loss) for a period be reduced by the amount of available cash that will be distributed with respect to that period and that any residual amount representing undistributed net income be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net income for the period had been distributed in accordance with the partnership agreement. Undistributed income is allocated to participating securities based on the distribution waterfall for available cash specified in the partnership agreement. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units and other participating securities on a pro rata basis based on provisions of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

Under our partnership agreement, the incentive distribution rights ("IDRs") participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss). We did not allocate earnings or losses to IDR holders for the purpose of the two class method earnings per unit calculation for any of the periods presented.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The following table provides a reconciliation of net income (loss) and the allocation of net income (loss) to the common units and the subordinated units for purposes of computing net income (loss) per unit (in thousands, except per unit data):

				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner
Year Ended December 31, 2012
Net loss	$	(150,136	)
Declared distributions	61,501			60,271			—		—			1,230
Amortization of beneficial conversion feature of Class B units	—			(5,149		)	25,319		(20,170		)	—
Assumed allocation of undistributed net loss	(211,637		)	(46,061		)	—		(157,917		)	(7,659		)
Assumed allocation of net income (loss)				$	9,061		$	25,319	$	(178,087	)	$	(6,429	)
Weighted average units outstanding				33,470			43,303		135,384
Net income (loss) per unit				$	0.27		$	0.58	$	(1.32	)
Year Ended December 31, 2011
Net loss	$	(31,019	)
Declared distributions	50,136			49,134			—		—			1,002
Assumed allocation of undistributed net loss	(81,155		)	(14,819		)	—		(64,713		)	(1,623		)
Assumed allocation of net income (loss)				$	34,315		$	—	$	(64,713	)	$	(621	)
Weighted average units outstanding				27,910			—		135,384
Net income (loss) per unit				$	1.23		$	—	$	(0.48	)
Year Ended December 31, 2010
Net income	$	107,568
Declared distributions	104,538			44,910			—		57,538			2,090
Assumed allocation of undistributed net loss	3,030			—			—		2,969			61
Assumed allocation of net income				$	44,910		$	—	$	60,507		$	2,151
Weighted average units outstanding				26,416			—		135,384
Net income per unit				$	1.70		$	—	$	0.45

NOTE 18—SUBSEQUENT EVENTS

Sabine Liquefaction Notes

In February 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $1.5 billion of 5.625% Senior Secured Notes due 2021 (the "Sabine Liquefaction Notes"). Net proceeds from the offering are intended to be used to pay capital costs incurred in connection with the construction of Train 1 and Train 2 of the Liquefaction Project in lieu of a portion of the commitments under the Liquefaction Credit Facility.

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SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

SUMMARIZED QUARTERLY FINANCIAL DATA

(unaudited)

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

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2012:
Revenues	$	69,323		$	61,396		$	66,308		67,300
Income from operations	24,891			18,275			772			19,602
Net loss	(19,332		)	(24,861		)	(42,422		)	(63,521		)
Net income (loss) per common unit—basic and diluted	$	0.23		$	0.17		$	0.04		$	(0.06	)
Year ended December 31, 2011:
Revenues	$	74,450		$	73,609		$	64,907		$	70,824
Income from operations	41,127			36,932			29,523			37,044
Net loss	(2,209		)	(6,868		)	(14,479		)	(7,463		)
Net income per common unit—basic and diluted	$	0.35		$	0.32		$	0.29		$	0.30

The sum of the quarterly net income per common unit may not equal the full year amount as the computations of the weighted average common unit outstanding for basic and diluted shares outstanding for each quarter and the full year are performed independently.

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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 general partner's 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, 2012, our general partner's 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 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 61 and is incorporated herein by reference.

ITEM 9B.     OTHER INFORMATION

Sabine Pass LNG Notes

On October 16, 2012, Sabine Pass LNG, L.P. ("Sabine Pass LNG"), our wholly owned subsidiary, closed the sale of $420 million aggregate principal amount of its 6.5% Senior Secured Notes due 2020 (the "2020 Notes") pursuant to the Purchase Agreement dated October 1, 2012 by and among Sabine Pass LNG and Credit Suisse Securities (USA) LLC and HSBC Securities (USA) Inc., as representatives of the initial purchasers named therein (the "Initial Purchasers"). The sale of the 2020 Notes was not registered under the Securities Act of 1933, as amended (the "Securities Act"), and the 2020 Notes were sold on a private placement basis in reliance on Section 4(2) of the Securities Act and Rule 144A and Regulation S thereunder.

Indenture

The 2020 Notes were issued pursuant to the Indenture, dated as of October 16, 2012 (the "Indenture"), by and among Sabine Pass LNG, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as trustee. Under the terms of the Indenture, the 2020 Notes will mature on November 1, 2020 and will accrue interest at a rate equal to 6.5% per annum on the principal amount from October 16, 2012 (the "issue date"), with such interest payable semi-annually, in cash in arrears, on May 1 and November 1 of each year, beginning May 1, 2013. The 2020 Notes are senior secured obligations of Sabine Pass LNG and rank senior in right of payment to any and all of Sabine Pass LNG's future indebtedness that is subordinated in right of payment to the 2020 Notes and equal in right of payment with all of Sabine Pass LNG's existing and future indebtedness that is senior and secured by the same collateral as that securing the 2020 Notes. The 2020 Notes are effectively senior to all of Sabine Pass LNG's senior indebtedness that is unsecured to the extent of the value of the assets constituting the collateral securing the 2020 Notes. The 2020 Notes are effectively subordinated to all of Sabine Pass LNG's indebtedness that is secured by assets other than the collateral securing the 2020 Notes, to the extent of the value of such assets, and is structurally subordinated to all indebtedness and other liabilities of Sabine Pass LNG's subsidiaries that do not provide guarantees with respect to the 2020 Notes.

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As of the issue date, the 2020 Notes were not guaranteed but will be guaranteed in the future by all of Sabine Pass LNG's future restricted subsidiaries that guarantee other indebtedness of Sabine Pass LNG, subject to certain exceptions. Such guarantees will be joint and several obligations of the guarantors of the 2020 Notes. The guarantees of the 2020 Notes will be senior secured obligations of the guarantors.

Sabine Pass LNG may, at its option, redeem all or part of the 2020 Notes at any time on or after November 1, 2016, at fixed redemption prices specified in the Indenture, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also, at its option, redeem all or part of the 2020 Notes at any time prior to November 1, 2016, at a "make-whole" price set forth in the Indenture, plus accrued and unpaid interest, if any, to the date of redemption. At any time before November 1, 2015, Sabine Pass LNG may, on one or more occasions, redeem up to 35% of the aggregate principal amount of the 2020 Notes at a redemption price of 106.5% of the principal amount of the 2020 Notes to be redeemed, plus accrued and unpaid interest, if any, to the redemption date, in an amount not to exceed the net proceeds of one or more completed equity offerings as long as it redeems the 2020 Notes within 180 days of closing such equity offering and at least 65% of the aggregate principal amount of the 2020 Notes issued under the Indenture on the issue date remains outstanding after the redemption.

The Indenture also contains customary terms, events of default and covenants relating to, among other things, incurring additional indebtedness or issuing preferred stock, making certain investments or paying dividends or distributions on capital stock or subordinated indebtedness or purchasing, redeeming or retiring capital stock, selling or transferring assets, including capital stock of Sabine Pass LNG's restricted subsidiaries, restricting dividends or other payments by Sabine Pass LNG's restricted subsidiaries, incurring liens, entering into transactions with affiliates, consolidating, merging, selling or leasing all or substantially all of Sabine Pass LNG's assets and entering into sale and leaseback transactions. In addition, Sabine Pass LNG will be required to deposit in a debt payment account one-sixth of the amount of interest due on the 2020 Notes and Sabine Pass LNG's outstanding 7.5% Senior Secured Notes due 2016 on the next interest payment date (plus any shortfall from any such month subsequent to the preceding interest payment date) at the end of each month. The Indenture covenants are subject to a number of important limitations and exceptions.

This description of the Indenture is qualified in its entirety by reference to the Indenture, a copy of which is filed as Exhibit 4.1 to Sabine Pass LNG's Current Report on Form 8-K filed on October 19, 2012, and is incorporated by reference herein.

Registration Rights Agreement

In connection with the closing of the sale of the 2020 Notes, Sabine Pass LNG and the Initial Purchasers entered into a Registration Rights Agreement, dated October 16, 2012 (the "Registration Rights Agreement"). Under the terms of the Registration Rights Agreement, Sabine Pass LNG has agreed, and any future guarantors of the 2020 Notes will agree, to use commercially reasonable efforts to file with the U.S. Securities and Exchange Commission and cause to become effective a registration statement with respect to an offer to exchange the 2020 Notes for a like aggregate principal amount of debt securities of Sabine Pass LNG issued under the Indenture and identical in all material respects with the 2020 Notes (other than with respect to restrictions on transfer or to any increase in annual interest rate) that are registered under the Securities Act. Sabine Pass LNG has agreed, and any future guarantors of the 2020 Notes will agree, to use commercially reasonable efforts to cause such registration statement to become effective within 360 days after the issue date. Under specified circumstances, Sabine Pass LNG has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the 2020 Notes. Sabine Pass LNG will be obligated to pay additional interest if it fails to comply with its obligations to register the 2020 Notes within the specified time periods.

This description of the Registration Rights Agreement is qualified in its entirety by reference to the Registration Rights Agreement, a copy of which is filed as Exhibit 10.1 to Sabine Pass LNG's Current Report on Form 8-K, filed on October 19, 2012, and is incorporated by reference herein.

Amendment to SPA with KOGAS

On February 18, 2013, Sabine Pass Liquefaction and KOGAS entered into Amendment No. 1 of LNG Sale and Purchase Agreement.  Amendment No. 1 amends the SPA entered into on January 30, 2012 between Sabine Pass Liquefaction and KOGAS to provide, among other things, that Sabine Pass Liquefaction will designate the date of the first commercial delivery of LNG from Train 3 within the 180-day period commencing 48 months after the date the conditions precedent have been satisfied or waived.  The amendment aligns the start date of the KOGAS SPA with the completion dates in the EPC Contract (Train 3 and Train 4).  In

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addition, Amendment No. 1 provides that the requirement that certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision to construct Train 3 be satisfied or waived on or prior to December 31, 2013, rather than June 30, 2013.

Amendment to SPA with GAIL

On February 18, 2013, Sabine Pass Liquefaction and GAIL entered into Amendment No. 1 of LNG Sale and Purchase Agreement.  Amendment No. 1 amends the SPA entered into on December 11, 2011 between Sabine Pass Liquefaction and GAIL to provide, among other things, that Sabine Pass Liquefaction will designate the date of the first commercial delivery of LNG from Train 4 within the 180-day period commencing 57 months after the date the conditions precedent have been satisfied or waived.  The amendment aligns the start date of the GAIL SPA with the completion dates in the EPC Contract (Train 3 and Train 4).  In addition, Amendment No. 1 provides that the requirement that certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision to construct Train 4 be satisfied or waived on or prior to December 31, 2013, rather than June 30, 2013.

PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS OF OUR GENERAL PARTNER AND CORPORATE

GOVERNANCE

Management of Cheniere Energy Partners, L.P.

Cheniere Energy Partners GP, LLC ("Cheniere GP"), as our general partner, manages our operations and activities. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. The directors of our general partner are elected by the sole member of the general partner. Unitholders are not entitled to elect the directors of our general partner or to participate directly or indirectly in our management or operations.

Audit Committee

The board of directors of our general partner has appointed an audit committee composed of Lon McCain, chairman, Oliver G. Richard, III and Vincent Pagano, Jr., each of whom is an independent director and satisfies the additional independence and other requirements for audit committee members provided for in the listing standards of the NYSE MKT and the Exchange Act. In addition, the board of directors of our general partner has determined that Lon McCain and Oliver G. Richard, III meet the qualifications of a "financial expert" and are "financially sophisticated" as such terms are defined by the SEC and the NYSE MKT, respectively.

The audit committee assists the board of directors of our general partner in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all audit services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the audit committee.

Conflicts Committee

Under our partnership agreement, the board of directors of our general partner has appointed a conflicts committee composed of the independent directors, Vincent Pagano, Jr., chairman, Lon McCain, Oliver G. Richard, III and James Robert Ball, to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of a conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be security holders, officers or employees of our general partner, directors, officers, or employees of affiliates of the general partner or holders of any ownership interest in us other than common units or other publicly traded units and must meet the independence standards established by the NYSE MKT, the Exchange Act and other federal securities laws. Any matter approved by the conflicts committee is conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties that it may owe us or our unitholders.

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Other

We do not have a nominating committee because the directors of our general partner manage our operations. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis. Unitholders are not entitled to elect the directors of our general partner or to participate directly or indirectly in our management or operations.

We also do not have a compensation committee. We have no employees, directors or officers. We are managed by our general partner, Cheniere GP. Our general partner has paid no cash compensation to its executive officers since its inception. All of the executive officers of our general partner are also executive officers of Cheniere. Cheniere compensates these officers for the performance of their duties as executive officers of Cheniere, which includes managing our partnership. Cheniere does not allocate this compensation between services for us and services for Cheniere and its affiliates.

Directors and Executive Officers of Our General Partner

We have no employees, directors or officers. We are managed by our general partner, Cheniere GP. The following sets forth information, as of February 15, 2013, regarding the individuals who currently serve on the board of directors and as executive officers of our general partner. Charif Souki has served as a director of the general partner since 2006. Meg Gentle and Lon McCain have served as directors of the general partner since 2007. Keith Teague has served as a director of the general partner since 2008. Messrs. Ball, Foley, Klimczak, Pagano, Richard and Thames were elected as directors of the general partner in 2012.

Name	Age	Position with Our General Partner
Charif Souki	60	Director, Chairman of the Board and Chief Executive Officer
R. Keith Teague	48	Director, President and Chief Operating Officer
Meg A. Gentle	38	Director, Senior Vice President and Chief Financial Officer
Lon McCain	65	Director
James R. Ball	62	Director
David I. Foley	45	Director
Sean T. Klimczak	36	Director
Vincent Pagano, Jr.	62	Director
Oliver G. Richard, III	60	Director
H. Davis Thames	45	Director

Charif Souki is Chairman of the Board of Directors and Chief Executive Officer of our general partner and has held that officer position since January 2007. Mr. Souki, a co-founder of Cheniere, is Chairman of Cheniere's board of directors and Chief Executive Officer and President of Cheniere. Since December 2002, Mr. Souki has been the Chief Executive Officer of Cheniere, and he was also President of Cheniere from that time until April 2005. He was re-elected as President in April 2008. From June 1999 to December 2002, he was Chairman of the board of directors of Cheniere and an independent investment banker. From September 1997 until June 1999, he was co-chairman of the board of directors of Cheniere, and he served as Secretary of Cheniere from July 1996 until September 1997. Mr. Souki has over 20 years of independent investment banking experience in the oil and gas industry and has specialized in providing financing for small capitalization companies with an emphasis on the oil and gas industry. Mr. Souki received a B.A. from Colgate University and an M.B.A. from Columbia University. Mr. Souki is also a director and Chief Executive Officer of the general partner of Sabine Pass LNG, L.P. It was determined that Mr. Souki should serve as a director of our general partner because he is the Chief Executive Officer of Cheniere, Cheniere GP and the general partner of Sabine Pass LNG, L.P. and is responsible for developing the companies' overall strategy and vision and implementing the business plans. In addition, with twenty years of experience as an investment banker specializing in the oil and gas industry, Mr. Souki brings a unique perspective to the board of directors of the general partner. Mr. Souki has not held any other directorship positions in the past five years.

R. Keith Teague is a director and President and Chief Operating Officer of our general partner and has held those officer positions since June 2008. He has served as Senior Vice President-Asset Group of Cheniere since April 2008. Prior to that time, he served as Vice President-Pipeline Operations of Cheniere beginning in May 2006. He has also served as President of Cheniere Pipeline Company, a wholly owned subsidiary of Cheniere, since January 2005. Mr. Teague began his career with Cheniere in February 2004 as Director of Facility Planning. Prior to joining Cheniere, Mr. Teague served as the Director of Strategic Planning for the CMS Panhandle Companies from December 2001 until September 2003. Mr. Teague is also President of the general partner

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of Sabine Pass LNG, L.P. and is responsible for the development, construction and operation of Cheniere's LNG terminal and pipeline assets. With Mr. Teague's knowledge and expertise relating to the Sabine Pass LNG terminal, it was determined that he should serve as a director of our general partner. Mr. Teague received a B.S. in civil engineering from Louisiana Tech University and an M.B.A. from Louisiana State University. Mr. Teague has not held any other directorship positions in the past five years.

Meg A. Gentle is a director and Senior Vice President and Chief Financial Officer of our general partner and has held that officer position since March 2009. She served as Senior Vice President of our general partner from June 2008 to March 2009. She has served as Senior Vice President and Chief Financial Officer of Cheniere since March 2009. She served as Senior Vice President - Strategic Planning and Finance from February 2008 to March 2009. Prior to that time, she served as Vice President of Strategic Planning since September 2005 and Manager of Strategic Planning since June 2004. Prior to joining Cheniere, Ms. Gentle spent eight years in energy market development, economic evaluation and long-range planning. She conducted international business development and strategic planning for Anadarko Petroleum Corporation, an oil and gas exploration and production company, for six years and energy market analysis for Pace Global Energy Services, an energy management and consulting firm, for two years. Ms. Gentle received her B.A. in economics and international affairs from James Madison University and an M.B.A. from Rice University. Ms. Gentle is also Chief Financial Officer of the general partner of Sabine Pass LNG, L.P. It was determined that Ms. Gentle should serve as a director of our general partner because of her experience with strategic planning and finance in the energy industry and because of the perspective she brings as the Chief Financial Officer of Cheniere, Cheniere GP and the general partner of Sabine Pass LNG, L.P. Ms. Gentle has not held any other directorship positions in the past five years.

James R. Ball is a director of our general partner and is a member of the Conflicts Committee. Mr. Ball has served as a non-executive director of Gas Strategies Group Ltd, a professional services company providing commercial energy advisory services (“GSG”), since September 2011. From 1988 until August 2011, he also served as an executive director of GSG. Since 2011, Mr. Ball has served as a senior advisor to Tachebois Limited, an energy and equities advisory firm. Mr. Ball is a Fellow of the Energy Institute and Companion of the Institute of Gas Engineers and Managers. Mr. Ball received a B.A. in economics from the University of Colorado and a Master of Science from City University Business School (now Cass Business School). Mr. Ball has not held any other directorship positions in the past five years. It was determined that Mr. Ball should serve as a director of our general partner because of his background as an advisor in the energy industry.

David I. Foleyis a director of our general partner. Mr. Foley is a Senior Managing Director in the Private Equity Group of The Blackstone Group L.P., an investment and advisory firm, and Chief Executive Officer of Blackstone Energy Partners L.P. Prior to joining Blackstone in 1995, Mr. Foley was an employee of AEA Investors Inc., a private equity investment firm, from 1991 to 1993 and a consultant with The Monitor Company, a business management consulting firm, from 1989 to 1991. Mr. Foley currently serves as a director of Kosmos Energy Ltd. and PBF Energy Inc. Mr. Foley received a B.A. and a Master of Arts in economics from Northwestern University and a Master of Business Administration from Harvard Business School. It was determined that Mr. Foley should serve as a director of our general partner because of his financial expertise and his experience in the energy industry.

Sean T. Klimczakis a director of our general partner. Mr. Klimczak is a Managing Director in the Private Equity Group of The Blackstone Group L.P., an investment and advisory firm. Prior to joining Blackstone in 2005, Mr. Klimczak was an Associate at Madison Dearborn Partners, a private equity investment firm, from 2001 to 2003 and an employee in the Mergers & Acquisitions department of the Investment Banking division of Morgan Stanley, a financial services firm, from 1998 to 2001. Mr. Klimczak received a B.B.A. in finance and business economics from Notre Dame and a Master of Business Administration from Harvard Business School. Mr. Klimczak has not held any other directorship positions in the past five years. It was determined that Mr. Klimczak should serve as a director of our general partner because of his significant investment experience with Blackstone.

Lon McCain is a director of our general partner and serves as the Chairman of the Audit Committee and a member of the Conflicts Committee. He was Executive Vice President and Chief Financial Officer of Ellora Energy Inc., a private, independent exploration and production company from July 2009 to August 2010. Prior to that, he was Vice President, Treasurer and Chief Financial Officer of Westport Resources Corporation, a publicly traded exploration and production company, from 2001 until the sale of that company to Kerr-McGee Corporation in 2004. From 1992 until joining Westport, Mr. McCain was Senior Vice President and Principal of Petrie Parkman & Co., an investment banking firm specializing in the oil and gas industry. From 1978 until joining Petrie Parkman, Mr. McCain held senior financial management positions with Presidio Oil Company, Petro-Lewis Corporation and Ceres Capital. He is currently on the board of directors of Crimson Exploration, Inc., a publicly traded oil and natural gas exploration and production company, and Continental Resources, Inc., a publicly traded oil and natural gas exploration and

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production company. During the past five years, he served as a director of Transzap, Inc., a privately held provider of digital data and electronic payment solutions. Mr. McCain received a B.S. in business administration and a Masters of Business Administration/Finance from the University of Denver. Mr. McCain was also an Adjunct Professor of Finance at the University of Denver from 1982 to 2005. It was determined that Mr. McCain should serve as a director of our general partner because of his experience as a chief financial officer for energy companies and his background as an investment banker in the energy industry.

Vincent Pagano, Jr.is a director of our general partner and serves as Chairman of the Conflicts Committee and as a member of the Audit Committee. Mr. Pagano served as a senior corporate partner of Simpson Thacher & Bartlett LLP, a law firm, with a focus on capital markets transactions and public company advisory matters from 1981 until his retirement at the end of 2012. Mr. Pagano earned his law degree, cum laude, from Harvard Law School and his B.S. in Engineering, summa cum laude, from Lehigh University and an M.S. in Engineering from the University of California Berkley. Mr. Pagano has not held any other directorship positions in the past five years. It was determined that Mr. Pagano should serve as a director of our general partner because of his capital markets expertise and his experience as an advisor to public companies on a variety of corporate matters.

Oliver G. Richard, IIIis a director of our general partner and serves as a member of the Audit Committee and Conflicts Committee. Mr. Richard has served as Chairman of Cleanfuel USA, an alternative vehicular fuel company, since September 2007 and, for the past five years, he has been the owner and president of Empire of the Seed LLC, a private consulting firm in the energy and management industries. Mr. Richard served as Chairman, President and Chief Executive Officer of Columbia Energy Group, a natural gas company, from 1995 until 2000. Mr. Richard was a Commissioner on the Federal Energy Regulatory Commission from 1982 until 1985. Mr. Richard currently serves as a director of Buckeye Partners, L.P. and American Electric Power Company, Inc. Mr. Richard received a B.S. in Journalism and a J.D. from Louisiana State University and a Master of Law in Taxation from Georgetown University. It was determined that Mr. Richard should serve as a director of our general partner because of his extensive background in the energy industry, including his experience in both the public and private sectors of the energy industry.

H. Davis Thamesis a director of our general partner. Mr. Thames has served as Senior Vice President, Marketing since December 2007 and President of Cheniere Marketing, LLC, a wholly-owned subsidiary of Cheniere, since November 2007. Prior to that time, he was Vice President Marketing, Strategy & Analysis and Executive Vice President of Cheniere Marketing, LLC since December 2006 and February 2007, respectively. Prior to joining Cheniere as Vice President Marketing & Analysis in July 2005, Mr. Thames worked for Cross Country Energy, LLC, from 2003 to 2005, Enron Corp from 2003 to 2005 and Flowserve Corp. from 1991 to 1999. Mr. Thames earned a B.S. in Mechanical Engineering from The University of Texas at Austin, an M.S. in Mechanical Engineering from Texas A&M University, and an M.B.A. from the UCLA Anderson School of Management. Mr. Thames has not held any other directorship positions in the past five years. It was determined that Mr. Thames should serve as a director of our general partner because of his engineering expertise and his experience in project finance within the energy industry.

Code of Ethics

Our Code of Business Conduct and Ethics covers a wide range of business practices and procedures and furthers our fundamental principles of honesty, loyalty, fairness and forthrightness. The Code of Business Conduct and Ethics was approved by the directors of our general partner. Our Code of Business Conduct and Ethics is posted at www.cheniereenergypartners.com. We also intend to post any changes to or waivers of our Code of Business Conduct and Ethics for the executive officers of our general partner on our website.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16 of the Exchange Act requires the directors and executive officers of our general partner and persons who own more than 10% of a registered class of our equity securities to file initial reports of ownership and reports of changes in ownership with the SEC. Such persons are required by SEC regulation to furnish us with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such forms furnished to us and written representations from the directors and executive officers of our general partner, we believe that all Section 16(a) filing requirements were met during 2012 in a timely manner.

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ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Our general partner has paid no cash compensation to its executive officers since its inception. All of the executive officers of our general partner are also executive officers of Cheniere. Cheniere compensates these officers for the performance of their duties as executive officers of Cheniere, which includes managing our partnership. Cheniere does not allocate this compensation between services for us and services for Cheniere and its affiliates. Instead, an affiliate of Cheniere provides us various general and administrative services, such as technical, commercial, regulatory, financial, accounting, treasury, tax and legal staffing and related support services, pursuant to a services agreement for which we pay a non-accountable overhead reimbursement charge of $2.8 million per quarter (indexed for inflation). For a description of the services agreement, see Note 13—"Related Party Transactions" of our Notes to Consolidated Financial Statements.

In 2007, the board of directors of our general partner adopted the Cheniere Energy Partners, L.P. Long-Term Incentive Plan for employees, consultants and directors of our general partner, employees of its affiliates and consultants to its subsidiaries. The purpose of the plan is to enhance attraction and retention of qualified individuals who are essential for the successful operation of our partnership and to encourage them to align their interests with our interests through an equity ownership stake in us. The plan allows for the grant of options, restricted units, phantom units and unit appreciation rights. Up to 1,250,000 units may be granted under the plan. The only awards that have been granted under the plan have been made to the non-management directors of our general partner in the form of phantom units to be settled in cash over a four-year vesting period.

Compensation Committee Report

As discussed above, the board of directors of our general partner does not have a compensation committee. In fulfilling its responsibilities, the board of directors of our general partner, acting in lieu of a compensation committee, has reviewed and discussed the Compensation Discussion and Analysis with management. Based on this review and discussion, the board of directors of our general partner recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

By the members of the board of directors of our general partner:  

Charif Souki

R. Keith Teague

Meg A. Gentle

James R. Ball

David I. Foley

Sean T. Klimczak

Lon McCain

Vincent Pagano, Jr.

Oliver G. Richard, III

H. Davis Thames

Compensation Committee Interlocks and Insider Participation

As discussed above, the board of directors of our general partner does not have a compensation committee. If any compensation is to be paid to our general partners' officers, the compensation would be reviewed and approved by the entire board of directors of our general partner because they perform the functions of a compensation committee in the event such committee is needed. None of the directors or executive officers of our general partner served as a member of a compensation committee of another entity that has or has had an executive officer who served as a member of the board of directors of our general partner during 2012.

Director Compensation

On May 29, 2007, the board of directors of our general partner approved an annual fee of $50,000 to each non-management director of our general partner for services as a director. Also approved were annual fees of $30,000 for the chairman of the audit committee; $15,000 for the members of the audit committee other than the chairman; and $5,000 for the chairman of the conflicts committee. All directors' fees are pro-rated from the date of election to the board and are payable quarterly. In addition to the

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annual fees paid to the non-management directors, commencing February 1, 2012 and ending May 31, 2012, the Chairman of the Conflicts Committee received a special monthly fee of $16,777 and each other member of the Conflicts Committee received a special monthly fee of $13,333 in connection with increased work performed by the Conflicts Committee in connection with the Liquefaction Project during that time. The special monthly fees were paid in arrears. In addition to the annual fees paid to the non-management directors, when they joined the board of directors Messrs. Ball, Bock, McCain, Pagano, Richard, Sutcliffe, Turkleson and Williams each received 12,000 phantom units pursuant to the terms of the Cheniere Energy Partners, L.P. Long-Term Incentive Plan. The Grant Date for each grant is as follows: May 29, 2007 for Messrs. McCain and Sutcliffe, September 10, 2008 for Mr. Williams, June 10, 2009 for Messrs. Bock and Turkleson, September 7, 2012 for Messrs. Ball and Richard and December 7, 2012 for Mr. Pagano. Each director will receive an additional 3,000 phantom units annually on each anniversary of the Grant Date. Vesting will occur for one-fourth of the phantom units on each anniversary of the Grant Date beginning on the first anniversary of the Grant Date. Upon vesting, the phantom units will be payable in cash in an amount equal to the fair market value of a common unit on such date. The directors receive no distributions, and no distributions accrue, on the outstanding phantom units.

Indemnification of Directors

We have entered into indemnification agreements with each of our directors, which provide for indemnification with respect to all expenses and claims that a director incurs as a result of actions taken, or not taken, on our behalf while serving as a director, officer, employee, controlling person, agent or fiduciary of Cheniere GP or any of our subsidiaries. Pursuant to the agreements, no indemnification will generally be provided (1) for claims brought by the director, except for a claim of indemnity under the indemnification agreement, if we approve the bringing of such claim, or if the Delaware Limited Liability Company Act requires providing indemnification because our director has been successful on the merits of such claim, (2) for claims under Section  16(b) of the Exchange Act, or (3) if there has been a final judgment entered by a court determining that the director acted in bad faith, engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. Indemnification will be provided to the extent permitted by law, Cheniere GP's certificate of formation and limited liability company agreement, and to a greater extent if, by law, the scope of coverage is expanded after the date of the indemnification agreements. In all events, the scope of coverage will not be less than what was in existence on the date of the indemnification agreements.

The following table shows the compensation of the board of directors of our general partner for the 2012 fiscal year:

Name	Fees Earned or Paid in Cash		Unit Awards (1)		Option Awards		Non-Equity Incentive Plan Compensation		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation		Total
Charif Souki (2)	$	—	$	—	$	—	$	—	$	—	$	—	$	—
R. Keith Teague(2)	—		—		—		—		—		—		—
Meg A. Gentle (2)	—		—		—		—		—		—		—
James R. Ball (3)	9,722		305,280		—		—		—		—		315,002
Mike Bock (4)	122,304		62,700		—		—		—		—		185,004
David I. Foley (5)	—		—		—		—		—		—		—
Sean T. Klimczak (5)	—		—		—		—		—		—		—
Lon McCain (6)	133,332		70,320		—		—		—		—		203,652
Vincent Pagano, Jr. (7)	—		249,000		—		—		—		—		249,000
Oliver G. Richard, III (8)	12,639		305,280		—		—		—		—		317,919
Robert J. Sutcliffe (9)	123,640		70,320		—		—		—		—		193,960
H. Davis Thames (2)	—		—		—		—		—		—		—
Don A. Turkleson (10)	40,694		62,700		—		—		—		—		103,394
Walter L. Williams (11)	40,694		—		—		—		—		11,794		52,488

(1) Reflects aggregate grant date fair value. The phantom units are to be settled in cash. The units are valued using the closing unit price on the date of grant and are revalued on a quarterly basis through the date of vesting.

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(2) Charif Souki, Keith Teague and Meg Gentle are executive officers of our general partner and are also executive officers of Cheniere. Davis Thames is an executive officer of Cheniere. Cheniere compensates these officers for the performance of their duties as executive officers of Cheniere, which includes managing our partnership. They do not receive additional compensation for service as directors.

(3) Mr. Ball was appointed as a director effective September 7, 2012 and was granted 12,000 phantom units with a grant date fair value of $305,280 on that date. As of December 31, 2012, he held 12,000 phantom units.

(4) Mr. Bock was granted 3,000 phantom units in 2012 with a grant date fair value of $62,700. Mr. Bock received $94,050 in cash upon the vesting of 4,500 phantom units in June 2012 and $62,250 in cash upon the vesting of 3,000 phantom units upon his removal as a director on December 7, 2012. As of December 31, 2012, he held 6,750 phantom units, which will be paid in cash subject to their normal vesting schedule.

(5) David Foley is a Senior Managing Director and Sean Klimczak is a Managing Director in the Private Equity Group of The Blackstone Group L.P and they do not receive additional compensation for service as directors.

(6) Mr. McCain was granted 3,000 phantom units in 2012 with a grant date fair value of $70,320. Mr. McCain received $70,320 in cash upon the vesting of 3,000 phantom units in May 2012. As of December 31, 2012, he held a total of 7,500 phantom units.

(7) Mr. Pagano was appointed as a director effective December 7, 2012 and was granted 12,000 phantom units with a grant date fair value of $249,000 on that date. As of December 31, 2012, he held 12,000 phantom units.

(8) Mr. Richard was appointed as a director effective September 7, 2012 and was granted 12,000 phantom units with a grant date fair value of $305,280 on that date. As of December 31, 2012, he held 12,000 phantom units.

(9) Mr. Sutcliffe was granted 3,000 phantom units in 2012 with a grant date fair value of $70,320. Mr. Sutcliffe received $70,320 in cash upon the vesting of 3,000 phantom units in May 2012 and $76,320 in cash upon the vesting of 3,000 phantom units upon his removal as a director on September 7, 2012. As of December 31, 2012, he held a total of 4,500 phantom units, which will be paid in cash subject to their normal vesting schedule.

(10) Mr. Turkleson was granted 3,000 phantom units in 2012 with a grant date fair value of $62,700. Mr. Turkleson received $94,050 in cash upon the vesting of 4,500 phantom units in June 2012 and $76,320 in cash upon the vesting of 3,000 phantom units upon his removal as a director on September 7, 2012. As of December 31, 2012, he held a total of 6,750 phantom units, which will be paid in cash subject to their normal vesting schedule.

(11) Mr. Williams received $132,877 in cash upon the vesting of 5,250 phantom units in September 2012. Mr. Williams was removed as a director effective September 7, 2012. As of December 31, 2012, he held a total of 4,500 phantom units, which will be paid in cash subject to their normal vesting schedule. Mr. Williams also had use of an office, parking space, laptop and blackberry at Cheniere's headquarters during 2012. The pro rata amount of office lease expense related to that space was approximately $3,348. The parking expense was approximately $3,442 and the laptop and blackberry expense was approximately $5,004.

ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, AND

RELATED UNITHOLDER MATTERS

The limited partner interest in our partnership is divided into units. As of February 13, 2013, the following units were outstanding: 39,488,488 common units, 135,383,831 subordinated units, 6,289,911 general partner units and 133,333,334 Class B units. The following table sets forth the beneficial ownership of our units owned of record and beneficially as of February 12, 2013 by:  

• each person who beneficially owns more than 5% of the units;

• each of the directors of our general partner;

• each of the executive officers of our general partner; and

• all directors and executive officers of our general partner as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. A person is also deemed

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to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities, and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. Except as indicated by footnote, the address for the beneficial owners listed below is 700 Milam Street, Suite 800, Houston, Texas 77002.

Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Class B Units Beneficially Owned	Percentage of Class B Units Beneficially Owned		Subordinated Units Beneficially Owned		Percentage of Subordinated Units Beneficially Owned		Percentage of Total Equity Securities Beneficially Owned
Cheniere Energy, Inc. (1)(2)	11,963,488	30	%	33,333,334	25	%	135,383,831		100	%	59	%
Cheniere LNG Holdings, LLC (2)	11,963,488	30	%	33,333,334	25	%	135,383,831		100	%	59	%
Cheniere Subsidiary Holdings, LLC (2)	—	—		—	—		135,383,831		100	%	43	%
Cheniere Common Units Holding, LLC (2)	11,963,488	30	%	—	—		—	—	—		4	%
Cheniere Class B Units Holding, LLC (2)	—	—		33,333,334	25	%	—		—		11	%
Blackstone CQP Holdco LP (4)	—	—		100,000,000	75	%	—		—		32	%
Charif Souki (3)	400,100	1	%	—	—		—		—		*
R. Keith Teague	—	—		—	—		—		—		—
Meg A. Gentle	8,035	*		—	—		—		—		*
James R. Ball	—	—		—	—		—		—		—
David I. Foley (5)	—	—		—	—		—		—		—
Sean T. Klimczak (5)	—	—		—	—		—		—		—
Lon McCain	—	—		—	—		—		—		—
Vincent Pagano, Jr.	—	—		—	—		—		—		—
Oliver G. Richard, III	—	—		—	—		—		—		—
H. Davis Thames	500	*		—	—		—		—		*
All executive officers and directors as a group (10 persons)	408,635	1	%	—	—	%	—		—		*

* Less than 1%

(1) Cheniere Energy, Inc. is the ultimate parent company of Cheniere LNG Holdings, LLC, Cheniere Subsidiary Holdings, LLC, Cheniere Common Units Holding, LLC and Cheniere Class B Units Holding, LLC and and may, therefore, be deemed to beneficially own the units held by Cheniere LNG Holdings, LLC, Cheniere Subsidiary Holdings, LLC, Cheniere Common Units Holding, LLC and Cheniere Class B Units Holding, LLC.

(2) Cheniere LNG Holdings, LLC owns 100% of the equity interests in our general partner and an 59% limited partner interest in us either directly or through Cheniere Subsidiary Holdings, LLC, Cheniere Common Units Holding, LLC and Cheniere Class B Units Holding, LLC each a wholly owned subsidiary, and may, therefore, be deemed to beneficially own the units held by Cheniere Subsidiary Holdings, LLC, Cheniere Common Units Holding, LLC and Cheniere Class B Units Holding, LLC

(3) Includes 400,100 units owned by Mr. Souki's wife.

(4) The address is 345 Park Avenue, 44th floor, New York, New York 10154.

(5) Messrs. Foley and Klimczak were appointed as directors of our general partner pursuant to an investors' rights agreement entered into in connection with Blackstone CQP Holdco LP's purchase of Class B units.

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Equity Compensation Plan Information

In 2007, the board of directors of our general partner adopted the Cheniere Energy Partners, L.P. Long-Term Incentive Plan. The following table provides certain information as of December 31, 2012 with respect to this plan:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in the first column)
Equity compensation plans approved by security holders	—	N/A	—
Equity compensation plans not approved by security holders	—	N/A	1,250,000
Total	—	N/A	1,250,000

(1) The phantom units that have been granted are payable in cash at the time of vesting in an amount equal to the fair market value of a common unit on such date.

For more information regarding the Long-Term Incentive Plan, see "Compensation Discussion and Analysis."

ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Related-Party Transactions

Prior to the completion of our initial public offering of common units in 2007, the managers of our general partner approved the distributions and payments to be made to our general partner and its affiliates in connection with our ongoing operations and, in the event of, our liquidation. During our operational stage, we will generally make cash distributions to our unitholders, including our affiliates, as described in Part II, Item 5, of this annual report on Form 10-K. Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Under the audit committee charter, the audit committee of our general partner is required to review and approve all transactions or series of related financial transactions, arrangements or relationships between the partnership and any related-party, if the amount involved exceeds $120,000 and such transactions have not been reviewed by the conflicts committee of our general partner. The following related-party transactions are in addition to those related-party transactions described in Note 13—"Related Party Transactions" of our Notes to Consolidated Financial Statements which is herein incorporated by reference. Except as described below, such related-party transactions were approved by the members of the board of directors of our general partner, which includes each member of the audit committee.

ISDA Master Agreement

In September 2007, Cheniere Marketing and Sabine Pass LNG entered into an International Swaps and Derivatives Association ("ISDA") Master Agreement that provides Sabine Pass LNG with the ability to hedge its future price risk from time to time. The ISDA Master Agreement was entered into in the event Sabine Pass LNG chooses to hedge some of its LNG purchases or gas sales and elects to implement such hedges through Cheniere Marketing, which already has ISDA agreements in place with third parties and accounts with futures brokers. There are no current transactions under this agreement. No amounts were paid to Cheniere Marketing under this agreement during the fiscal years ended December 31, 2012 and 2011.

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Operational Balancing Agreement

In December 2007, Sabine Pass LNG and Cheniere Creole Trail Pipeline, L.P. entered into an Operational Balancing Agreement that provides for the resolution of any operational imbalances (i) during the term of the agreement on an in-kind basis and (ii) upon termination of the agreement by cash-out at a rate equivalent to the average of the midpoint prices for Henry Hub, Louisiana pricing published in "Gas Daily’s-Daily Price Survey" for each day of the month following termination. This agreement became effective following the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008. Sabine Pass LNG owed a natural gas volume valued at $47,000 and $56,000 to Cheniere Creole Trail Pipeline, L.P. at December 31, 2012 and 2011, respectively.

LNG Terminal Export Agreement

In January 2010, Sabine Pass LNG and Cheniere Marketing entered into an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  Sabine Pass LNG recorded revenues—affiliate of $0.3 million pursuant to this agreement in the years ended December 31, 2012 and 2011.

The following related-party transactions were not approved by the board of directors or audit committee of our general partner:

Letter Agreement regarding the Cooperative Endeavor Agreement and Payment in Lieu of Taxes Agreement

In July 2007, Sabine Pass LNG entered into Cooperative Endeavor Agreements with various Cameron Parish, Louisiana taxing authorities and a related agreement with Cheniere Marketing, each as described in Note 13—"Related Party Transactions" of our Notes to Consolidated Financial Statements. During each of the years ended December 31, 2012 and 2011, Cheniere Marketing paid Sabine Pass LNG $2.5 million under the agreement.

Temporary Pipeline Compressor Sharing Agreement

In August 2010, Sabine Pass LNG entered into an agreement with its TUA customers, including Cheniere Energy Investments, LLC ("Cheniere Investments"), to share in the cost for the installation and operation of a temporary pipeline compressor at the Sabine Pass LNG terminal. Sabine Pass LNG recorded costs of $0.1 million and $0.4 million under this agreement in the years ended December 31, 2012 and 2011, respectively. During the years ended December 31, 2012 and 2011, Sabine Pass LNG recorded revenues—affiliate from Cheniere Investments of $0.1 million and $0.4 million, respectively, pursuant to this agreement.

Independent Directors

Because we are a limited partnership, the NYSE MKT does not require our general partner's board of directors to be composed of a majority of directors who meet the criteria for independence required by NYSE MKT. The board of our general partner has determined that Mike Bock, Lon McCain and Robert Sutcliffe are independent directors in accordance with the following NYSE MKT independence standards. A director would not be independent if any of the following relationships exists:

• a director who is, or during the past three years was, employed by the partnership, general partner or by any parent or subsidiary of the partnership or general partner;  

• a director who accepts, or has an immediate family member who accepts, any compensation from the partnership, general partner or any parent or subsidiary of the partnership or general partner in excess of $120,000 during any twelve consecutive-month period or any of the past three fiscal years, other than compensation for board or committee services, or compensation paid to an immediate family member who is a non-executive employee of the partnership, general partner or any parent or subsidiary of the partnership or general partner, among other exceptions;  

• a director who is an immediate family member of an individual who is, or has been in any of the past three years, employed by the partnership, general partner or any parent or subsidiary of the partnership or general partner as an executive officer; 

• a director who is, or has an immediate family member who is, a partner in, or a controlling shareholder or an executive officer of, any organization to which the partnership, general partner or any parent or subsidiary of the partnership or general partner made, or from which the partnership, general partner or any parent or subsidiary of the partnership or general partner received, payments (other than those arising solely from investments in our common units or payments

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under non-discretionary charitable contribution matching programs) that exceed 5% of the organization's consolidated gross revenues for that year, or $200,000, whichever is more, in any of the most recent three fiscal years;  

• a director who is, or has an immediate family member who is, employed as an executive officer of another entity where at any time during the most recent three fiscal years any of the executive officers of the partnership, general partner or any parent or subsidiary of the partnership or general partner serves on the compensation committee of such other entity; or  

• a director who is, or has an immediate family member who is, a current partner of the outside auditor of the partnership, general partner or parent or subsidiary of the partnership or general partner, or was a partner or employee of the outside auditor of the partnership, general partner or any parent or subsidiary of the partnership or general partner who worked on our audit at any time during any of the past three years. 

ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES

Ernst & Young LLP served as our independent auditor for the fiscal years ended December 31, 2012 and 2011. The following table sets forth the fees paid to Ernst & Young LLP for professional services rendered for 2012 and 2011: 

	Ernst & Young LLP
	Fiscal 2012		Fiscal 2011
Audit Fees	$	1,376,834	$	1,062,227
Audit-Related Fees	253,777		171,767
Total	$	1,630,611	$	1,233,994

Audit Fees—Audit fees for 2012 and 2011 include attestation services and review of documents filed with the SEC in addition to audit, review and all other services performed to comply with generally accepted auditing standards.

Audit-Related Fees—Audit-related fees for 2012 and 2011 include services rendered in connection with the offering of securities in a registration statement.

There were no tax or other fees in 2012 and 2011.

Auditor Pre-Approval Policy and Procedures

Under the audit committee’s charter, the audit committee is required to review and approve in advance all audit and lawfully permitted non-audit services to be provided by the independent accountants and the fees for such services. Pre-approval of non-audit services (other than review and attestation services) shall not be required if such services fall within exceptions established by the SEC. All audit and non-audit services provided to us during the fiscal years ended December 31, 2012 and 2011 were pre-approved.

PART IV

ITEM 15.     EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements and Exhibits

(1) Financial Statements—Cheniere Energy Partners, L.P.:

Management’s Report to the Unitholders of Cheniere Energy Partners, L.P.	55
Reports of Independent Registered Public Accounting Firm—Ernst & Young LLP	56
Consolidated Balance Sheets	58
Consolidated Statements of Operations	59
Consolidated Statements of Partners’ and Owners’ Capital (Deficit)	61
Consolidated Statements of Cash Flows	62
Notes to Consolidated Financial Statements	63
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data	88

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(2) Financial Statement Schedules:

Schedule I—Condensed Financial Information of Registrant for the years ended December 31, 2012, 2011 and 2010 108

(3) Exhibits 

Exhibit No.	Description
2.1*	Contribution and Conveyance Agreement. (Incorporated by reference to Exhibit 10.4 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on March 26, 2007)
3.1*	Certificate of Limited Partnership of Cheniere Energy Partners, L.P. (Incorporated by reference to Exhibit 3.1 to Cheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on December 21, 2006)
3.2*	Third Amended and Restated Agreement of Limited Partnership of Cheniere Energy Partners, L.P., dated as of August 9, 2012. (Incorporated by reference to Exhibit 3.1 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
3.3*	Certificate of Formation of Cheniere Energy Partners GP, LLC. (Incorporated by reference to Exhibit 3.3 to Cheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on December 21, 2006)
3.4*	Third Amended and Restated Limited Liability Company Agreement of Cheniere Energy Partners GP, LLC, dated as of August 9, 2012. (Incorporated by reference to Exhibit 3.2 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
4.1*	Form of common unit certificate. (Incorporated by reference to Exhibit A to Exhibit 3.2 above)
4.2*	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 Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
4.3*	Form of 7.50% Senior Secured Note due 2016. (Included as Exhibit A1 to Exhibit 4.2 above)
4.4*	Indenture, dated as of October 16, 2012, by and among Sabine Pass LNG, L.P., the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as trustee. (Incorporated by reference to Exhibit 4.1 to Sabine Pass LNG L.P.’s Current Report on Form 8-K (SEC File No. 001-138916), filed on October 19, 2012)
4.5*	Form of 6.5% Senior Secured Note due 2020. (Included as Exhibit A1 to Exhibit 4.4 above)
4.6*	Indenture, dated as of February 1, 2013, by and among Sabine Pass Liquefaction, LLC, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as trustee. (Incorporated by reference to Exhibit 4.1 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on February 4, 2013)
4.7*	Form of 5.625% Senior Secured Note due 2021. (Included as Exhibit A-1 to Exhibit 4.6 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 Cheniere Energy, Inc.'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 Cheniere Energy, Inc.'s Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 10, 2005)
10.3*	Amendment of LNG Terminal Use Agreement, dated June 15, 2010, by and between Total Gas & Power North America, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 6, 2010)
10.4*	Letter Agreement, dated September 11, 2012, between Total Gas & Power North America, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)

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10.5*	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 Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.6*	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 Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001 16383), filed on November 15, 2004)
10.7*	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 Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.8*	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)
10.9*	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 Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 6, 2010)
10.10*	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 Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004)
10.11*	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)
10.12*	Second Amended and Restated Terminal Use Agreement, dated as of July 31, 2012, between Sabine Pass LNG, L.P. and Sabine Pass Liquefaction, LLC. (Incorporated by reference to Exhibit 10.1 to Sabine Pass LNG, L.P.’s Current Report on Form 8-K (SEC File No. 333-138916), filed on August 6, 2012)
10.13*	Guarantee Agreement, dated as of July 31, 2012, by Cheniere Energy Partners, L.P. in favor of Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.1 to Sabine Pass LNG, L.P.’s Current Report on Form 8-K (SEC File No. 333-138916), filed on August 6, 2012)
10.14*	Cooperative Endeavor Agreement & Payment in Lieu of Tax Agreement, dated October 23, 2007. (Incorporated by reference to Exhibit 10.7 to Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2007)
10.15*	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)
10.16*	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 Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on November 21, 2011)
10.17*	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 Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on December 12, 2011)
10.18	Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between Sabine Pass Liquefaction, LLC (Seller) and GAIL (India) Limited (Buyer).
10.19*	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 Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on January 30, 2012)
10.20	Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 18, 2013, between Sabine Pass Liquefaction, LLC (Seller) and Korea Gas Corporation (Buyer).

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10.21*	LNG Sale and Purchase Agreement (FOB), dated May 14, 2012, by and between Sabine Pass Liquefaction, LLC and Cheniere Marketing, LLC. (Incorporated by reference to Exhibit 10.7 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.22*	LNG Sale and Purchase Agreement (FOB), dated December 14, 2012, between Sabine Pass Liquefaction, LLC (Seller) and Total Gas & Power North America, Inc. (Buyer). (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on December 14, 2012)
10.23*	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 and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to the SEC's grant of a confidential treatment request.) (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on November 14, 2011)
10.24*	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0001 EPC Terms and Conditions, dated May 1, 2012, (ii) the Change Order CO-0002 Heavies Removal Unit, dated May 23, 2012, (iii) the Change Order CO-0003 LNTP, dated June 6, 2012, (iv) the Change Order CO-0004 Addition of Inlet Air Humidification, dated July 10, 2012, (v) the Change Order CO-0005 Replace Natural Gas Generators with Diesel Generators, dated July 10, 2012, (vi) the Change Order CO-0006 Flange Reduction and Valve Positioners, dated July 12, 2012, and (vii) the Change Order CO-0007 Relocation of Temporary Facilities, Power Poles Relocation Reimbursement, and Duck Blind Road Improvement Reimbursement, dated July 13, 2012. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on August 3, 2012)
10.25*	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0008 Delay in Full Placement of Insurance, dated July 27, 2012, (ii) the Change Order CO-0009 HAZOP Action Items, dated July 31, 2012, (iii) the Change Order CO-0010 Fuel Provisional Sum, dated August 8, 2012, (iv) the Change Order CO-0011 Currency Provisional Sum, dated August 8, 2012, (v) the Change Order CO-0012 Delay in NTP, dated August 8, 2012, and (vi) the Change Order CO-0013 Early EPC Work Credit, dated August 29, 2012. (Incorporated by reference to Exhibit 10.2 to Cheniere Energy Partners L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.26	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Liquefaction Facility, dated as of November 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc.: (i) the Change Order CO-0014 Bundle of Changes, dated September 5, 2012, (ii) the Change Order CO-0015 Static Mixer, Air Cooler Walkways, etc., dated November 8, 2012, (iii) the Change Order CO-0016 Delay in Full Placement of Insurance, dated October 29, 2012, (iv) the Change Order CO-0017 Condensate Header, dated December 3, 2012 and (v) the Change Order CO-0018 Increase in Power Requirements, dated January 17, 2013. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment.)
10.27*	Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility, dated December 20, 2012, by and between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to the SEC’s grant of a confidential treatment request.) (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on December 27, 2012)
10.29*	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 Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 11, 2008)
10.30*	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 Cheniere Energy, Inc.'s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 7, 2011)
10.31*	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 Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)

104

10.32*	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 Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.33*	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 Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.34*	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 Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.35*	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 Cheniere Energy, Inc.'s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006)
10.36*	Amended and Restated Operation and Maintenance Agreement (Sabine Pass LNG Facilities), dated as of August 9, 2012, by and among Cheniere LNG O&M Services, LLC, Cheniere Energy Partners GP, LLC and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.5 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.37*	Amended and Restated Management Services Agreement, dated as of August 9, 2012, by and between Cheniere LNG Terminals, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference to Exhibit 10.6 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.38*	Operation and Maintenance Agreement (Sabine Pass Liquefaction Facilities), dated May 14, 2012, by and among Cheniere LNG O&M Services, LLC, Cheniere Energy Partners GP, LLC and Sabine Pass Liquefaction, LLC. (Incorporated by reference to Exhibit 10.5 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.39*	Management Services Agreement, dated May 14, 2012, by and between Cheniere LNG Terminals, Inc. and Sabine Pass Liquefaction, LLC. (Incorporated by reference to Exhibit 10.6 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.40*	Amended and Restated Services and Secondment Agreement, dated as of August 9, 2012, between Cheniere LNG O&M Services, LLC and Cheniere Energy Partners GP, LLC. (Incorporated by reference to Exhibit 10.3 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.41*	Amended and Restated Management and Administrative Services Agreement, dated as of August 9, 2012, by and between Cheniere Energy Partners, L.P., Cheniere LNG Terminals, Inc. and Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.4 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.42*	Registration Rights Agreement, dated October 16, 2012, by and among Sabine Pass LNG, L.P. and Credit Suisse Securities (USA) LLC and HSBC Securities (USA) Inc. (Incorporated by reference to Exhibit 10.1 to Sabine Pass LNG, L.P.’s Current Report on Form 8-K (SEC File No. 001-138916), filed on October 19, 2012)
10.43*	Registration Rights Agreement, dated February 1, 2013, between Sabine Pass Liquefaction, LLC and Morgan Stanley & Co. LLC. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on February 4, 2013)
10.44*	Unit Purchase Agreement, dated May 14, 2012, by and among Cheniere Energy Partners, L.P., Cheniere Energy, Inc. and Blackstone CQP Holdco LP. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.45*	Letter Agreement, dated as of August 9, 2012, among Cheniere Energy, Inc., Cheniere Energy Partners, L.P. and Blackstone CQP Holdco LP. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)

105

10.46*	Class B Unit Purchase Agreement, dated as of May 14, 2012, by and between Cheniere Energy Partners, L.P. and Cheniere LNG Terminals, Inc. (Incorporated by reference to Exhibit 10.2 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.47*	First Amendment to Class B Unit Purchase Agreement, dated as of August 9, 2012, by and between Cheniere Energy Partners, L.P. and Cheniere Class B Units Holdings, LLC. (Incorporated by reference to Exhibit 10.3 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
10.48*	Investors’ and Registration Rights Agreement, dated as of July 31, 2012, by and among Cheniere Energy, Inc., Cheniere Energy Partners, L.P., Cheniere Energy Partners GP, LLC, Cheniere Class B Units Holdings, LLC, Blackstone CQP Holdco LP and the other investors party thereto from time to time. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Current Report on 8-K (SEC File No. 001-33366), filed on August 6, 2012)
10.49*	Amended and Restated Purchase and Sale Agreement, dated as of August 9, 2012, by and among Cheniere Energy Partners, L.P., Cheniere Pipeline Company, Grand Cheniere Pipeline, LLC and Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.2 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on August 9, 2012)
10.50*	Subscription Agreement, dated May 14, 2012, by and between Cheniere Energy Partners, L.P. and Cheniere LNG Terminals, Inc. (Incorporated by reference to Exhibit 10.4 to Cheniere Energy Partners, L.P.’s Current Report on Form 8-K (SEC File No. 001-33366), filed on May 15, 2012)
10.51*	Credit Agreement (Term Loan A), dated as of July 31, 2012, among Sabine Pass Liquefaction, LLC, Société Générale, as Term Loan A Administrative Agent and Common Security Trustee, and the lenders party thereto from time to time. (Incorporated by reference to Exhibit 10.4 to Cheniere Energy Partners, L.P.’s Current Report on 8-K (SEC File No. 001-33366), filed on August 6, 2012)
10.52*	Common Terms Agreement, dated as of July 31, 2012, among Sabine Pass Liquefaction, LLC, the Secured Debt Holder Group Representatives, the Secured Hedge Representatives, the Secured Gas Hedge Representatives, the Intercreditor Agent and Société Générale, as Common Security Trustee. (Incorporated by reference to Exhibit 10.5 to Cheniere Energy Partners, L.P.’s Current Report on 8-K (SEC File No. 001-33366), filed on August 6, 2012)
10.53*†	Cheniere Energy Partners, L.P. 2007 Long-Term Incentive Plan. (Incorporated by reference to Exhibit 10.3 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on March 26, 2007)
10.54*†	Form of Restricted Units Agreement for employees, consultants and directors (three-year). (Incorporated by reference to Exhibit 10.39 to Cheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on March 2, 2007)
10.55*†	Form of Restricted Units Agreement for employees, consultants and directors (four-year). (Incorporated by reference to Exhibit 10.40 to Cheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on March 2, 2007)
10.56*†	Form of Director Units Option Agreement for employees and consultants (four-year). (Incorporated by reference to Exhibit 10.41 to Cheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on March 2, 2007)
10.57*†	Form of Units Option Agreement for employees and consultants (three-year). (Incorporated by reference to Exhibit 10.42 to Cheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on March 2, 2007)
10.58*†	Form of Units Option Agreement for employees and consultants (four-year). (Incorporated by reference to Exhibit 10.43 to Cheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on March 2, 2007)
10.59*†	Form of Phantom Units Agreement for employees, consultants and directors (four-year). (Incorporated by reference to Exhibit 10.44 to Cheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on March 2, 2007)

106

10.60*†	Form of Phantom Units Agreement for employees, consultants and directors (three-year). (Incorporated by reference to Exhibit 10.45 to Cheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on March 2, 2007)
10.61*†	Form of Phantom Units Agreement. (Incorporated by reference to Exhibit 10.2 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on June 4, 2007)
10.62*†	Form of Amendment to Phantom Units Agreement. (Incorporated by reference to Exhibit 10.7 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.63*†	Form of Phantom Units Agreement under the Cheniere Energy Partners, L.P. Long-Term Incentive Plan. (Incorporated by reference to Exhibit 10.8 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.64*†	Form of Phantom Units Agreement under the Cheniere Energy Partners, L.P. Long-Term Incentive Plan (2012 Reload Award). (Incorporated by reference to Exhibit 10.9 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed on November 2, 2012)
10.65*†	Summary of Compensation for Independent Directors. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on June 4, 2007)
10.66*†	Form of Indemnification Agreement for officers and/or directors of Cheniere Energy Partners GP, LLC. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC File No. 001-33366), filed on April 6, 2009)
21.1	Subsidiaries of Cheniere Energy Partners, L.P.
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
101.INS+	XBRL Instance Document
101.SCH+	XBRL Taxonomy Extension Schema Document
101.CAL+	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF+	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB+	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE+	XBRL Taxonomy Extension Presentation Linkbase Document

*	Incorporated by reference
†	Management contract or compensatory plan or arrangement
+	Pursuant to Rule 406T of Regulation S-T, the interactive data files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

107

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—

CHENIERE ENERGY PARTNERS, L.P.

CONDENSED BALANCE SHEET

(in thousands)

	December 31,
	2012		2011
ASSETS
Current assets
Cash and cash equivalents	$	392,945	$	56,119
Advances to affiliate	—		136
Prepaid expenses and other	134		135
Total current assets	393,079		56,390
Investment in affiliates	972,395		—
Non-current receivable—affiliates	940		47,238
Other	874		—
Total assets	$	1,367,288	$	103,628
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities	$	4,480	$	3,806
Equity in losses of affiliates	—		644,841
Commitments and contingencies
Stockholders' equity (deficit)	1,362,808		(545,019		)
Total liabilities and stockholders’ deficit	$	1,367,288	$	103,628

See accompanying notes to condensed financial statements.

108

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—

CHENIERE ENERGY PARTNERS, L.P.

CONDENSED STATEMENT OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2012			2011			2010
Revenues	$	—		$	—		$	—
Operating costs and expenses	18,262			13,104			14,723
Loss from operations	(18,262		)	(13,104		)	(14,723		)
Interest expense, net	12			—			—
Interest income	235			38			51
Equity income (loss) of affiliates	(132,121		)	(17,953		)	122,240
Net income (loss)	$	(150,136	)	$	(31,019	)	$	107,568

See accompanying notes to condensed financial statements.

109

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—

CHENIERE ENERGY PARTNERS, L.P.

CONDENSED STATEMENT OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2012			2011			2010
Cash flows from operating activities	$	(17,508	)	$	(13,948	)	$	(10,193	)
Cash flows from investing activities
Investment in subsidiaries	(1,832,440		)	—			(20,918		)
Other	3			—			—
Net cash used in investing activities	(1,832,437		)	—			(20,918		)
Cash flows from financing activities:
Proceeds from sale of Class B units	1,887,342			—			—
Distributions received from affiliates, net	61,529			59,910			229,608
Distributions to owners	(57,821		)	(48,149		)	(163,249		)
Proceeds from sale of partnership units	250,021			70,157			—
Affiliate receivable	46,574			(38,333		)	(8,896		)
Deferred financing costs	(874		)	—			—
Net cash provided by financing activities	2,186,771			43,585			57,463
Net increase in cash and cash equivalents	336,826			29,637			26,352
Cash and cash equivalents—beginning of year	56,119			26,482			130
Cash and cash equivalents—end of year	$	392,945		$	56,119		$	26,482

See accompanying notes to condensed financial statements.

110

CHENIERE ENERGY PARTNERS, L.P.

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 Partners, L.P. ("Cheniere Partners").

In the condensed financial statements, Cheniere Partners’ 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 sheets. The gain/(loss) from operations of the affiliates is reported on a net basis as equity in net gains/(losses) of affiliates.

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

NOTE 2—SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Non-cash capital contributions (1)	$	(132,121	)	$	(17,953	)	122,240

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

111

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 PARTNERS, L.P.
By:	Cheniere Energy Partners GP, LLC, its general partner
By:	/s/    CHARIF SOUKI
	Charif Souki
	Chief Executive Officer and
	Chairman of the Board
Date:	February 22, 2013

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 general partner of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Charif Souki	Chief Executive Officer & Chairman of the Board	February 22, 2013
Charif Souki	(Principal Executive Officer)
/s/ R. Keith Teague	President and Chief Operating Officer,	February 22, 2013
R. Keith Teague	Director (Principal Operating Officer)
/s/ Meg A. Gentle	Senior Vice President & Chief Financial Officer,	February 22, 2013
Meg A. Gentle	Director (Principal Financial Officer)
/s/ Jerry D. Smith	Chief Accounting Officer	February 22, 2013
Jerry D. Smith	(Principal Accounting Officer)
/s/ James R. Ball	Director	February 22, 2013
James R. Ball
/s/ David I. Foley	Director	February 22, 2013
David I. Foley
/s/ Sean T. Klimczak	Director	February 22, 2013
Sean T. Klimczak
/s/ Lon McCain	Director	February 22, 2013
Lon McCain
/s/ Vincent Pagano Jr.	Director	February 22, 2013
Vincent Pagano Jr.
/s/ Oliver G. Richard, III	Director	February 22, 2013
Oliver G. Richard, III
/s/ H. Davis Thames	Director	February 22, 2013
H. Davis Thames

112

EX-10.18

EXHIBIT 10.18

AMENDMENT NO. 1 OF LNG SALE AND PURCHASE AGREEMENT

THIS AMENDMENT NO. 1 OF LNG SALE AND PURCHASE AGREEMENT (“Amendment”) is made and entered into as of February 18, 2013, by and between Sabine Pass Liquefaction, LLC, a Delaware limited liability company whose principal place of business is located at 700 Milam St., Suite 800, Houston, TX 77002 (“Seller”), and GAIL (India) Limited, a company incorporated and existing under the laws of India whose principal place of business is located at 16, Bhikaiji Cama Place, R.K. Puram, New Delhi, India 110066 (“Buyer”). Buyer and Seller are each referred to herein as a “Party” and collectively as the “Parties”.

Recitals

(A) Seller and Buyer are parties to that certain LNG Sale and Purchase Agreement dated as of December 11, 2011 (“Agreement”); and

(B) Seller and Buyer desire to amend the Agreement to clarify the rights and obligations of the Parties under the Agreement regarding certain conditions precedent, start-up timing, and other terms, all as set forth herein.

It is agreed:

1. Definitions

Capitalized terms used in or incorporated into this Amendment and not otherwise defined herein have the meanings given to them in the Agreement.

2.Amendments

2.1.Section 1.1 of the Agreement is amended by deleting in their entirety the definitions of “Bridging    

Period”, “Bridging Start Date”, and “Bridging Volume”.

2.2.Section 1.1 of the Agreement is further amended by deleting in its entirety the definition of “Designated

Train”, and the following definition is inserted in lieu thereof:

Designated Train: (i) the second (2^nd) Train to be constructed at the Sabine Liquefaction Facility pursuant to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility dated December 20, 2012, between Seller and Bechtel Oil, Gas and Chemicals, Inc.; (ii) in the event that the agreement described in clause (i) were to be terminated and a replacement engineering, procurement and construction contract were to be entered into by Seller for the third (3^rd) and fourth (4^th) Trains to be constructed at

- 1 -

the Sabine Liquefaction Facility, the second (2^nd) Train to be constructed pursuant to such contract; or (iii) in the event that the agreement described in clause (i) were to be terminated and a replacement engineering, procurement and construction contract were to be entered into by Seller solely for the fourth (4^th) Train to be constructed at the Sabine Liquefaction Facility, the Train to be constructed pursuant to such contract;

2.3. Section 2.2.1(c) of the Agreement is amended by deleting the last “and” therein.

2.4. Section 2.2.1(d) of the Agreement is deleted in its entirety, and the following Section 2.2.1(d) is inserted in lieu thereof:

(d) the Approvals required for Seller to export LNG from the Designated Train are in full force and effect; and

2.5. A new Section 2.2.1(e) is added to the Agreement as follows:

(e) Seller has issued to the Person primarily responsible for construction of the Designated Train and any other facilities at the Sabine Pass Facility needed to enable Seller to fulfill its obligations under this Agreement, an unconditional full notice to proceed with the construction of the Designated Train and any other facilities at the Sabine Pass Facility needed to enable Seller to fulfill its obligations under this Agreement.

2.6. Section 2.2.3 of the Agreement is amended by deleting the words “June 30^th, 2013” and replacing them with the words “December 31^st, 2013”.

2.7. Section 4.2.1 of the Agreement is deleted in its entirety, and the following Section 4.2.1 is inserted in lieu thereof:

4.2.1 The period that begins on the first Day of the Month that follows the date that is fifty-seven (57) Months after the CP Fulfillment Date and ends one hundred eighty (180) Days later shall be the “First Window Period”.

2.8. Section 4.5 of the Agreement is deleted in its entirety.

2.9. All provisions of the Agreement not specifically amended hereby shall remain in full force and effect.

- 2 -

3. Miscellaneous

3.1. Dispute Resolution; Immunity. The provisions of Section 21.1 (Dispute Resolution) and Section 21.4 (Immunity) of the Agreement shall apply in this Amendment as if incorporated herein mutatis mutandis on the basis that references therein to the Agreement are to this Amendment.

3.2. Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of New York (United States of America) without regard to principles of conflict of laws that would specify the use of other laws.

3.3. Entire Agreement. The Agreement, as amended by this Amendment, constitutes the entire agreement between the Parties and includes all promises and representations, express or implied, and supersedes all other prior agreements and representations, written or oral, between the Parties relating to the subject matter thereof.

3.4. Amendments and Waiver. This Amendment may not be supplemented, amended, modified or changed except by an instrument in writing signed by Seller and Buyer and expressed to be a supplement, amendment, modification or change to the Agreement. A Party shall not be deemed to have waived any right or remedy under this Amendment by reason of such Party's failure to enforce such right or remedy.

3.5. Counterparts. This Amendment may be executed in two counterparts and each such counterpart shall be deemed an original Amendment for all purposes, provided that neither Party shall be bound to this Amendment unless and until both Parties have executed a counterpart.

- 3 -

IN WITNESS WHEREOF, the Parties hereto have executed this Amendment as of the date first above written.

SELLER:	BUYER:
SABINE PASS LIQUEFACTION, LLC	GAIL (INDIA) LIMITED
/s/ H. D. Thames	/s/ Rajesh Vedvyas
Name: H. Davis Thames	Name: Rajesh Vedvyas
Title: Executive Vice President	Title: Executive Director

- 4 -

EX-10.19

EXHIBIT 10.19

AMENDMENT NO. 1 OF LNG SALE AND PURCHASE AGREEMENT

THIS AMENDMENT NO. 1 OF LNG SALE AND PURCHASE AGREEMENT (“Amendment”) is made and entered into as of February 18, 2013, by and between Sabine Pass Liquefaction, LLC, a Delaware limited liability company whose principal place of business is located at 700 Milam St., Suite 800, Houston, TX 77002 (“Seller”), and Korea Gas Corporation, a corporation organized under the laws of the Republic of Korea, whose principal place of business is located at 171 Dolma-ro (Jeongja-Dong), Bundang-Gu, Seongnam, Gyeonggi-Do, 463-754, Republic of Korea (“Buyer”). Buyer and Seller are each referred to herein as a “Party” and collectively as the “Parties”.

Recitals

(A) Seller and Buyer are parties to that certain LNG Sale and Purchase Agreement dated as of January 30, 2012 (“Agreement”); and

(B) Seller and Buyer desire to amend the Agreement to clarify the rights and obligations of the Parties under the Agreement regarding certain conditions precedent, start-up timing, and other terms, all as set forth herein.

It is agreed:

1. Definitions

Capitalized terms used in or incorporated into this Amendment and not otherwise defined herein have the meanings given to them in the Agreement.

2. Amendments

2.1. Section 1.1 of the Agreement is amended by deleting in its entirety the definition of “Designated Train”, and the following definition is inserted in lieu thereof:

Designated Train: the first (1^st) LNG production train to be constructed at the Sabine Liquefaction Facility pursuant to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 2 Liquefaction Facility dated December 20, 2012, between Seller and Bechtel Oil, Gas and Chemicals, Inc., including those facilities included in the Sabine Pass Facility that are necessary to enable Seller to fulfill its obligations to Buyer from such LNG production train;

2.2. Section 2.2.1(c) of the Agreement is amended by deleting the last “and” therein.

- -1 -

2.3. Section 2.2.1(d) of the Agreement is deleted in its entirety, and the following Section 2.2.1(d) is inserted in lieu thereof:

(d) the Approvals required for Seller to export LNG from the Designated Train are in full force and effect; and

2.4. A new Section 2.2.1(e) is added to the Agreement as follows:

(e) Seller has issued to the Person primarily responsible for construction of the Designated Train and any other facilities at the Sabine Pass Facility needed to enable Seller to fulfill its obligations under this Agreement, an unconditional full notice to proceed with the construction of the Designated Train and any other facilities at the Sabine Pass Facility needed to enable Seller to fulfill its obligations under this Agreement.

2.5. Section 2.2.3 of the Agreement is amended by deleting the words “June 30^th, 2013” and replacing them with the words “December 31^st, 2013”.

2.6. Section 4.2 of the Agreement is amended by deleting the words “Subject to Section 4.3” in the first paragraph of Section 4.2 and replacing them with the words “Subject to Section 4.4”.

2.7. Section 4.2.1 of the Agreement is amended by deleting the words “fifty-nine (59) Months” and replacing them with the words “forty-eight (48) Months”.

2.8. Section 4.2.6 of the Agreement is amended by deleting the words “Subject to Section 4.3” and replacing them with the words “Subject to Section 4.4”.

2.9. Section 4.3 of the Agreement is deleted in its entirety, and the words “Intentionally omitted.” are inserted in lieu thereof.

2.10. All provisions of the Agreement not specifically amended hereby shall remain in full force and effect.

3. Miscellaneous

3.1. Dispute Resolution; Immunity. The provisions of Section 21.1 (Dispute Resolution) and Section 21.4 (Immunity) of the Agreement shall apply in this Amendment as if incorporated herein mutatis mutandis on the basis that references therein to the Agreement are to this Amendment.

3.2. Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of New York (United States of America) without regard to principles of conflict of laws that would specify the use of other laws.

- -2 -

3.3. Entire Agreement. The Agreement, as amended by this Amendment, constitutes the entire agreement between the Parties and includes all promises and representations, express or implied, and supersedes all other prior agreements and representations, written or oral, between the Parties relating to the subject matter thereof.

3.4. Amendments and Waiver. This Amendment may not be supplemented, amended, modified or changed except by an instrument in writing signed by Seller and Buyer and expressed to be a supplement, amendment, modification or change to the Agreement. A Party shall not be deemed to have waived any right or remedy under this Amendment by reason of such Party's failure to enforce such right or remedy.

3.5. Counterparts. This Amendment may be executed in two counterparts and each such counterpart shall be deemed an original Amendment for all purposes, provided that neither Party shall be bound to this Amendment unless and until both Parties have executed a counterpart.

- -3 -

IN WITNESS WHEREOF, the Parties hereto have executed this Amendment as of the date first above written.

SELLER:	BUYER:
SABINE PASS LIQUEFACTION, LLC	KOREA GAS CORPORATION
/s/ H. D. Thames	/s/ Kwon, Young Sik
Name: H. Davis Thames	Name: Kwon, Young Sik
Title: Executive Vice President	Title: EVP, Resources Business Division

- -4 -

EX-10.26

EXHIBIT 10.26

CHANGE ORDER FORM

COP Technical Bulletin #4, Stage 2 Flare Tie-Ins, Additional DCS Furniture, Non-Redline Items

PROJECT NAME:  Sabine Pass LNG Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 11, 2011 CHANGE ORDER NUMBER: CO-00014 DATE OF CHANGE ORDER: September 5, 2012

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1. Per Article 6.1.B of the Agreement, Parties agree to implement COP Technical Bulletin #4 which changes piping metallurgy from carbon steel to stainless steel in the refrigeration compressor suction piping and associated flanges. A copy of COP Bulletin #4 is attached as Exhibit A to this Change Order. This Change Order also includes the additional controls associated with COP Technical Bulletin #4 recommended by COP to Cheniere. The additional controls list is Exhibit B to this Change Order.

2. Per Article 6.1.B of the Agreement, Parties agree to add the following additional DCS furniture for stacked space:

a. Two (2) additional displays for HIS 0755

b. Two (2) additional displays for HIS 0756

c. Two (2) additional displays for HIS 0757

d. Two (2) additional displays for HIS 0758

e. Two (2) displays for Cheniere E-Mail, Logbook personal computer.

3. Per Article 6.1.B of the Agreement, Parties agree that Bechtel will install tie-in valves for stage 2 flare system. Current refrigerant area and BOG system currently shares commonality between Stage 1 and Stage 2 with ties into Stage 1 flare system only. Installing the tie-in valves for stage 2 is necessary to avoid a complete shutdown of Train 1 and Train 2.

a. P&ID's M6-0010-00107 and M6-1010-00107 associated with the stage 2 flare tie-ins are attached as Exhibit C to this Change Order.

4. The Non-Redline Action Items described in Exhibit D of this Change Order are hereby added to the scope of work under the Agreement.

5. This Contract Change Order will increase the Contract price by a fixed lump sum amount of $7,125,052. Accordingly, the Agreement is modified as follows:

a. Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the Milestone(s) listed in Exhibit E of this Change Order.

6. The overall cost breakdown data for all changes is provided in Exhibit F of this Change Order.

7. The cost breakdown data for COP Technical Bulletin #4 is provided in Exhibit G of this Change Order.

8. The cost breakdown data for the additional DCS furniture is provided in Exhibit H of this Change Order.

9. The cost breakdown data for installing the tie-in valves for the Stage 2 flare system is provided in Exhibit I of this Change Order.

10. The cost breakdown data for the Non-Redline Action Items is provided in Exhibit J of this Change Order

Adjustment to Contract Price

The original Contract Price was................................................................................................................................$3,900,000,000

Net change by previously authorized Change Orders (#0001-00013) .....................................................................$ 59,649,341

The Contract Price prior to this Change Order was..................................................................................................$3,959,649,341

The Contract Price will be (increased) by this Change Order

in the amount of .......................................................................................................................................................$ 7,125,052

The new Contract Price including this Change Order will be..................................................................................$3,966,774,393

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): No impact to Project Schedule.

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes. See sections 5, 6, 7, 8, 9, 10 and Exhibit E, F, G, H, I, and J of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties' duly authorized representatives.

/s/ Ed Lehotsky	/s/ J. Jackson
Owner	Contractor
Ed Lehotsky	JT Jackson
Name	Name
VP LNG Project Management	Sr. Vice President
Title	Title
September 26, 2012	September 7, 2012
Date of Signing	Date of Signing

CHANGE ORDER FORM

LNG Static Mixer, Additional Walkways for Hudson Coolers, Early EPC Additional Reimbursement, Credit

to Change Order 00014 Negotiation

PROJECT NAME:  Sabine Pass LNG Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 11, 2011 CHANGE ORDER NUMBER: CO-00015 DATE OF CHANGE ORDER: November 8, 2012,

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1. Per Article 6.1.B of the Agreement, Parties agree Bechtel will install two (2) static mixers, one on each pair of the LNG loading lines to the East and West Jetty locations in the Existing Facility. This work was previously within Sabine Pass Liquefaction, LLC's scope and therefore excluded from the LSTK proposal provided by Bechtel. There is no performance specification at the outlet of the static mixer governing the degree of mixing required. Computational Fluid Dynamic (CFD) simulations were based on a SPL, LLC. specified mixing efficiency of at least 95%. Each mixer will be fabricated in 2 sections which will be welded (no flanges) and contain 2 internal orifice plates which will be 70% open by diameter. The middle section will be 48” in diameter and the end connections will be 30”. The mixer will contain an analyzer probe port.

a. Any modifications, including structural and piping supports to the Existing Facility identified by the revisions to G&HES transient analysis (25611-200-K0R-DK-00001-00B dated July 18, 2011) are excluded. The transient analysis is expected to be completed in 1Q 2013. Final assessment of the LNG static mixer design can be completed at that time.

b. Any modifications to existing facilities or the new LNG in-tank Pumps identified by the revisions to the pump network study and the revised LNG in-tank Pump calculations are excluded. Final verification of the ship loading hydraulic study (25697-100-M0R-24-00001 dated May 30, 2012) and the in-tank pump calculation (25697-100-MPC-24-0P101) will be completed in 1Q 2013.

c. Attachment X of the Agreement will be updated to include the addition of the two static mixers.

d. The Previous Existing Facility Labor Provisional Sum in Article 2.2 of Attachment EE of the Agreement was *** U.S. Dollars ($***) and *** hours for direct craft. This Change Order will amend the previous values respectively to *** U.S. Dollars ($***) and *** hours.

e. The previous Aggregate Provisional Sum after the executed Change Order CO-00011, dated August 8, 2012 included Two Hundred Sixty Two Million, One Hundred Ninety Four Thousand, Four Hundred and Forty Four U.S. Dollars ($262,194,444). This Change Order will amend that value and the new value shall be Two Hundred Sixty Two Million, Five Hundred Forty Thousand, Seven Hundred and Fifty One U.S. Dollars ($262,540,751).

2. Per Article 6.1.B of the Agreement, Parties agree that Bechtel will add six (6) interconnected walkways per train between each alternative air cooler bay. Additionally, Bechtel will provide additional lighting to the extended access walkways. The basis of these additions is to provide secondary access for plant personnel.

3. An adjustment for a miscalculation on the Early Works Credit Recap dated September 5, 2012 will be applied to this Change Order.

4. Bechtel will credit SPL as a concession to the professional service costs in Change Order 00014.

5. The Second Sentence to Attachment A, page A-1 is hereby amended by:

• deleting the phrase “The priority of between these documents is set forth in Section 1.3 of Attachment A, Schedule A-1.”

• replacing it with “The priority of between these documents is set forth in Section 1.4 of Attachment A, Schedule A-1.”

6. This Contract Change Order will increase the Contract price by an amount of $2,551,141. The breakdown of this amount is $2,204,834 lump sum increase and $346,307 increase in aggregate provisional sum as noted in Section 1.e of this Change Order. Accordingly, the Agreement is modified as follows:

a. Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the Milestone(s) listed in Exhibit A of this Change Order.

7. The overall cost breakdown data for all changes is provided in Exhibit B of this Change Order.

8. The cost breakdown data for the addition of the 2 static mixers is provided in Exhibit C of this Change Order.

9. The cost breakdown data for the additions of the walkways and lighting to the air cooler bays is provided in Exhibit D of this Change Order.

10. The cost breakdown data for the miscalculation to the Early Works Credit Recap is provided in Exhibit E of this Change Order.

11. The cost breakdown data for the concession to professional service costs in Change Order 00014 is provided in Exhibit F of this Change Order.

12. The cost breakdown for the addition to the Existing Facility Labor Provisional Sum is provided in Exhibit G of this Change Order.

13. The drawing depicting the locations of the Static Mixers is attached as Exhibit H of this Change Order.

14. The drawing depicting the locations of the interconnected walkways is attached as Exhibit I of this Change Order.

Adjustment to Contract Price

The original Contract Price was ...............................................................................................................................$3,900,000,000

Net change by previously authorized Change Orders (#0001-00014) .....................................................................$ 66,774,393

The Contract Price prior to this Change Order was .................................................................................................$3,966,774,393

The Contract Price will be (increased) by this Change Order

in the amount of.........................................................................................................................................................$ 2,551,141

The new Contract Price including this Change Order will be ..................................................................................$3,969,325,534

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): No impact to Project Schedule.

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes. See sections 1.d, 1.e, 6, 7, 8, 9, 10, 11 and Exhibit A, B, C, D, E, F, and G of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order, with the exception of the actions and deliverables specified in Item 1.a - 1.e, shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties' duly authorized representatives.

/s/ Ed Lehotsky	/s/ Sergio Buoncristiano
Owner	Contractor
Ed Lehotsky	Segio Buoncristiano
Name	Name
VP LNG Project Management	Principal Vice President
Title	Title
November 20, 2012	November 9, 2012
Date of Signing	Date of Signing

CHANGE ORDER FORM

Second Delay in Full Placement of Insurance Program

PROJECT NAME:  Sabine Pass LNG Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 11, 2011 CHANGE ORDER NUMBER: CO-0016 DATE OF CHANGE ORDER: October 29, 2012

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1. Sections 1.A9(e) of Attachment O is hereby amended and restated as follows:

(e) Sum Insured: The insurance policy shall (i) be on a completed value form, with no periodic reporting requirements, (ii) insure not less than $1,000,000,000 commencing at LNTP and insure one hundred percent (100%) of the Facility's insurable values commencing no later March 31, 2013, (iii) value losses at replacement cost, without deduction for physical depreciation or obsolesce including custom duties, Taxes and fees and (iv) insure loss or damage from earth movement without a sub-limit, (v) insure property loss or damage from flood and named windstorm with a sub-limit not less than $150,000,000 commencing at LNTP, provided that such sub-limit shall increase to an amount that is not less than $500,000,000 no later than fifty-six (56) Days after NTP, and such sub-limit in the event of a named windstorm shall apply to the combined loss covered under Section 1.A.9 Builder's Risk and Section 1.A.10 Builder's Risk Delayed Startup, and (vi) insure loss or damage from strikes, riots and civil commotion with a sub-limit not less than $100,000,000.

2. Section 1.3 of Attachment EE is hereby amended as follows:

1.3Insurance Provisional Sum

The Aggregate Provisional Sum contains a Provisional Sum of *** U.S. Dollars (U.S.$***) (“Insurance Provisional Sum”) for the cost of insurance premiums for the insurance required to be provided by Contractor in accordance with Attachment O (other than workers compensation and employer liability insurance) (the “Project Insurances”). Contractor shall notify Owner in writing no later than March 31, 2013 of the actual cost of the insurance premiums charged to Contractor by Contractor's insurance carrier for the Project Insurances (“Actual Insurance Cost”), which Actual Insurance Cost shall be adequately documented by Contractor. If the Actual Insurance Cost is less than the Insurance Provisional Sum, Owner shall be entitled to a Change Order reducing the Contract Price by such difference. If the Actual Insurance Cost is greater than the Insurance Provisional Sum, Contractor shall be entitled to a Change Order increasing the Contract Price by such difference. Contractor shall be responsible for the placement of the Project Insurances required to be provided by Contractor in accordance with Attachment O, provided that Contractor shall reasonably cooperate with Owner to minimize such Actual Insurance Cost to the extent reasonably practicable.

The Contract Price has been based upon naming the Owner Group as additional insureds on the commercial general liability and umbrella or excess liability policies specified in Section 1A.2 and 1A.4 of Attachment O and providing sudden and accidental pollution liability coverage (including clean up on or off the Site) under such commercial general liability policy. Accordingly, should (i) the insurance provider(s) charge any additional premium for naming the Owner Group as named insureds under such policies as compared to naming the Owner Group as additional insureds or (ii) Contractor not be able to procure such sudden and

accidental liability coverage and, instead, is required to procure a stand-alone pollution policy, Contractor shall be entitled to a Change Order increasing the Contract Price in the actual amount of such increased premium associated with naming the Owner Group as named insureds rather than additional insureds or procurement of such stand-alone pollution policy.

Adjustment to Contract Price

No Adjustment to Contract Price associated with CO-00016

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Adjustment to other Changed Criteria: if no changes or impact; attach additional documentation if necessary): N/A

Adjustment to Payment Schedule: N/A

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties' duly authorized representatives.

/s/ Ed Lehotsky	/s/ J. Jackson
Owner	Contractor
Ed Lehotsky	JT Jackson
Name	Name
VP LNG Project Management	Sr. Vice President
Title	Title
November 7, 2012	October 29, 2012
Date of Signing	Date of Signing

CHANGE ORDER FORM

Condensate Header

PROJECT NAME:  Sabine Pass LNG Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 11, 2011 CHANGE ORDER NUMBER: CO-00017 DATE OF CHANGE ORDER: December 3, 2012

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1. Per Article 6.1.B of the Agreement, Parties agree Bechtel will add a condensate header originating at the battery limits of ISBL Trains 1 and 2 and terminating at a point southeast of LNG Tank S-104. The scope of work includes:

a. Design and installation of a condensate header originating at the battery limits of Trains 1 and 2 and terminating at a pipe rack location southeast of LNG Tank S-101. Refer to Exhibit D of this Change Order for the overall pipe routing of the new condensate header.

b. The condensate delivery pressure will be 10 psig at the location and mid-level pipe rack elevation of 145'-6” as shown in Exhibit B of this Change Order.

c. Hydraulic calculation to confirm the line sizes and delivery pressure shown in Exhibits A, B, and C of this Change Order. The line sizes shown in Exhibits A and C are based on a normal condensate flow of 24 gallons per minute (gpm) per train and a total normal output of 96 gpm for four (4) trains.

d. 6 inch double block and bleed tie-in valves will be provided in Stage 1 for the future Stage 2 condensate header from Trains 3 and 4 as shown in Exhibits A and C of this Change Order.

e. Exhibit C of this Change Order shows the applicable P&ID markups for this work.

f. Exhibit D of this Change Order shows the Greenfield and Brownfield scope of work delineation.

g. Attachment X of the Agreement will be updated to include the addition of the condensate header.

h. The previous Existing Facility Labor Provisional Sum in Article 2.2 of Attachment EE of the Agreement was ***#U.S. Dollars ($***) and *** hours. This Change Order will amend the previous values respectively to *** U.S. Dollars ($***) and *** hours.

i. The previous Aggregate Provisional Sum after Change Order CO-0015, dated November 8, 2012, was Two Hundred Sixty Two Million, Five Hundred Forty Thousand, Seven Hundred and Fifty One U.S. Dollars ($262,540,751). This Change Order will amend that value and the new value shall be Two Hundred Sixty Three Million, Five Hundred Eighty Four Thousand, Three Hundred Seventy Seven U.S. Dollars ($263,584,377).

2. The following are clarifications and exclusions related to this work:

a. No pre-investment piping for Stage 2 to be provided, only double block and bleed tie-in valves are to be provided near the southwest corner of Train 1.

b. No off-specification condensate handling system will be provided. Handling of off-specification

condensate from Unit 18 will be Sabine Pass Liquefaction, LLC's responsibility.

c. No isolation valves to be provided at the Sabine Pass Liquefaction, LLC. / Bechtel interface location. Isolation valves are already provided at the battery limit of each LNG train.

d. Sabine Pass Liquefaction, LLC. / Bechtel tie-in interface will be located at the mid-level pipe rack, elevation 145'-6”, rather than the lower level originally requested by Sabine Pass Liquefaction, LLC due to lack of space at the lower level.

e. The safety review of Unit 23 and closure of Action items 363 and 364 from the Unit 18 HAZOP will be Sabine Pass Liquefaction, LLC's responsibility and is excluded from this Change Order. See Attachment E of this Change Order.

f. Any modifications to systems upstream of Sabine Pass Liquefaction, LLC's scope of work, as a result of the subsequent Unit 23 safety review are excluded from the scope of this Change Order.

3. This Contract Change Order will increase the Contract price by a fixed lump sum amount of $2,534,523. The breakdown of this amount is a $1,490,897 lump sum increase and a $1,043,626 increase in aggregate provisional sum as noted in Section 1.i of this Change Order. Accordingly, the Agreement is modified as follows:

a. Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the Milestone(s) listed in Exhibit F of this Change Order.

4. The overall cost breakdown data for all changes is provided in Exhibit G of this Change Order.

5. The cost breakdown data for the addition to the Existing Facility Labor Provisional Sum is provided in Exhibit H of this Change Order.

Adjustment to Contract Price

The original Contract Price was................................................................................................................................$3,900,000,000

Net change by previously authorized Change Orders (#0001-00016) .....................................................................$ 69,325,534

The Contract Price prior to this Change Order was...................................................................................................$3,969,325,534

The Contract Price will be (increased) by this Change Order

in the amount of.........................................................................................................................................................$ 2,534,523

The new Contract Price including this Change Order will be...................................................................................$3,971,860,057

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert N/A if no dates modified): No impact to Project Schedule.

Adjustment to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes. See sections 1.g, 1.h, 3, 4, 5 and Exhibits F, G, and H of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties' duly authorized representatives.

/s/ Ed Lehotsky	/s/ J. Jackson
Owner	Contractor
Ed Lehotsky	JT Jackson
Name	Name
VP LNG Project Management	Sr. Vice President
Title	Title
December 21, 2012	December 12, 2012
Date of Signing	Date of Signing

CHANGE ORDER FORM

Increase in Power Requirements to Cheniere Buildings

PROJECT NAME:  Sabine Pass LNG Liquefaction Facility OWNER: Sabine Pass Liquefaction, LLC CONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc. DATE OF AGREEMENT: November 11, 2011 CHANGE ORDER NUMBER: CO-00018 DATE OF CHANGE ORDER: January 17, 2013

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if

necessary)

1. Per Article 6.1.B of the Agreement, Parties agree Bechtel will provide the material, labor, and subcontract cost for additional electrical requirements to the O&M and Warehouse buildings. The scope of work includes:

a. Changing normal power feeder cable to the new O&M building electrical room to 600A/480V with the trip set at 490A.

b. Adding standby 1OOA/480V feeder to electrical room of new O&M building.

2. Per Article 6.1.B of the Agreement, Parties agree Bechtel will provide additional electrical equipment needed for the design change to support spare power requirements. The scope of work includes:

a. Adding four (4) new 13.8 13.8kV sections including all instrumentation and relaying, with the exception of circuit breakers.

b. Converting spare breakers included in the new Synch bus into a spare feeder.

c. Converting equipped space included in the new Synch bus into a spare feeder.

d. PMS circuitry is a requirement for this expansion.

e. Exhibit A of this Change Order shows the proposed modifications referenced above.

3. This Contract Change Order will increase the Contract price by an amount of $681,444. The breakdown of this amount is a $598,430 lump sum increase and an $83,014 increase in aggregate provisional sum as noted in item 5 of this Change Order. Accordingly, the Agreement is modified as follows:

a. Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the Milestone(s) listed in Exhibit B of this Change Order.

4. The previous Existing Facility Labor Provisional Sum in Article 2.2 of Attachment EE of the Agreement was to U.S. Dollars ($***) and *** hours. This Change Order will amend the previous values respectively to U.S. Dollars ($***) and

*** hours.

5. The previous Aggregate Provisional Sum after Change Order C0-0017, dated December 21, 2012, was Two Hundred Sixty Three Million, Five Hundred Eighty Four Thousand, Three Hundred Seventy Seven U.S. Dollars ($263,584,377). This Change Order will amend that value and the new value shall be Two Hundred Sixty Three Million, Six Hundred Sixty Seven Thousand, Three Hundred Ninety One U.S. Dollars ($263,667,391).

6. The overall cost breakdown data for all changes is provided in Exhibit C of this Change Order.

7. The cost breakdown data for the addition to the Existing Facility Labor Provisional Sum is provided in Exhibit D

of this Change Order.

Adjustment to Contract Price

The original Contract Price was .............................................................................................................................$3,900,000,000

Net change by previously authorized Change Orders (#0001-00017)....................................................................$ 71,860,057

The Contract Price prior to this Change Order was ...............................................................................................$3,971,860,057

The Contract Price will be (increased) by this Change Order

in the amount of .....................................................................................................................................................$     681,444

The new Contract Price including this Change Order will be ................................................................................$3,972,541,501

Adjustment to dates in Project Schedule

The following dates are modified (list all dates modified; insert NIA if no dates modified): No impact to Project

Schedule.

Adjustment to other Changed Criteria (insert NIA if no changes or impact; attach additional documentation if

necessary)

Adjustment to Payment Schedule: Yes. See sections 3, 4, 5 and Exhibits B, C, and D of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Design Basis: N/A

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A orB:

.     .

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the

change reflected in this Change Order upon tanged Criteria and shall be deemed to compensate Contractor fully for such change. Initials: ____Contractor_____ Owner

[B] This change order shall not constitute a full and final settlement and accord and satisfaction of all effects of the

change reflected in this Change Order upon tanged Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____Contractor    _____ Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties' duly authorized representatives

/s/ Ed Lehotsky	/s/ Sergio Buoncristiano
Owner	Contractor
Ed Lehotsky	Segio Buoncristiano
Name	Name
VP LNG Project Management	Principal Vice President
Title	Title
February 4, 2013	January 18, 2013
Date of Signing	Date of Signing

EX-21.1

EXHIBIT 21.1

List of Subsidiaries or Other Related Entities of Company

Cheniere Energy Investments, LLC

Cheniere Midstream Services, LLC

Cheniere NGL Pipeline, LLC

Sabine Pass Liquefaction, LLC

Sabine Pass Liquefaction Expansion, LLC

Sabine Pass LNG-GP, LLC

Sabine Pass LNG-LP, LLC

Sabine Pass LNG, L.P.

Sabine Pass Liquefaction, LLC

Sabine Pass Liquefaction Expansion, LLC

Sabine Pass Tug Services, LLC

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statements (Form S-3 No. 333-168942, 333-183780 and 333-183986 and Form S-8 No. 333-151155) of our reports dated February 22, 2013, with respect to the consolidated financial statements and schedule of Cheniere Energy Partners, L.P. and subsidiaries, and the effectiveness of internal control over financial reporting of Cheniere Energy Partners, L.P. and subsidiaries, included in this Annual Report (Form 10-K) for the year ended December 31, 2012.

/s/ ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

February 22, 2013

EX-31.1

EXHIBIT 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER PURSUANT TO

RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Charif Souki, certify that:

1. I have reviewed this Annual Report on Form 10-K of Cheniere Energy Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 22, 2013

/s/ CHARIF SOUKI

Charif Souki

Chief Executive Officer of Cheniere Energy Partners GP, LLC, the general partner of Cheniere Energy Partners, L.P.

EX-31.2

EXHIBIT 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Meg A. Gentle, certify that:

1. I have reviewed this Annual Report on Form 10-K of Cheniere Energy Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 22, 2013

/s/ MEG A. GENTLE

Meg A. Gentle

Chief Financial Officer of Cheniere Energy Partners GP, LLC, the general partner of Cheniere Energy Partners, L.P.

EX-32.1

Exhibit 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

In connection with the Annual Report of Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-K for the year ended December 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charif Souki, Chief Executive Officer of the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

Date: February 22, 2013

/s/ CHARIF SOUKI

Charif Souki

Chief Executive Officer of Cheniere Energy Partners GP, LLC, the general partner of Cheniere Energy Partners, L.P.

EX-32.2

EXHIBIT 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Cheniere Energy Partners, L.P. (the “Partnership”) on Form 10-K for the year ended December 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Meg A. Gentle, Chief Financial Officer of the general partner of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

Date: February 22, 2013

/s/ MEG A. GENTLE

Meg A. Gentle

Chief Financial Officer of Cheniere Energy Partners GP, LLC, the general partner of Cheniere Energy Partners, L.P.

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Initial Public Offering (Details) (USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended	1 Months Ended		0 Months Ended	1 Months Ended		12 Months Ended		0 Months Ended
	Mar. 26, 2007	Sep. 30, 2012	May 31, 2012	Mar. 26, 2007 Common Units	Sep. 30, 2012 Common Units	Sep. 30, 2011 Common Units	Dec. 31, 2012 Common Units	Dec. 31, 2011 Common Units	Mar. 26, 2007 General Partner [Member]	Mar. 26, 2007 Limited Partner [Member]	Mar. 26, 2007 Chenier Energy Partners, LP [Member]	Mar. 26, 2007 Chenier Energy Partners, LP [Member] Common Units	Mar. 26, 2007 Cheniere LNG Holdings [Member]	Mar. 26, 2007 Cheniere LNG Holdings [Member] Common Units	Mar. 26, 2007 Cheniere LNG Holdings [Member] Subordinated Units	Mar. 26, 2007 Cheniere LNG Holdings [Member] Limited Partner [Member]	Mar. 26, 2007 Cheniere LNG Holdings [Member] Limited Partner [Member] Common Units	Mar. 26, 2007 Minimum [Member] General Partner [Member]
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Units, Sold in Public Offering	13,500,000			5,054,164	8,000,000	3,000,000	500,000	500,000				5,054,164		8,445,836			8,445,836
Partners Capital Account, Sale Of Units, Ownership Percentage After Transaction										8.20%						89.80%
Partners Capital Account, Units, Sold In Public Offering, Unit Price	$ 21.00	$ 15.00			$ 25.07
Partners' Capital Account, Units, Sold in Private Placement			133,300,000						3,302,045					21,362,193	135,383,831
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest									2.00%
Related Party Transactions, Commitments, Annual Reservation Fee Payment									$ 10.0
Relatedd Party Transactions, Quarterly Overhead Reimbursement Charge									2.8
Proceeds from Issuance Initial Public Offering											$ 98.4		$ 164.5
Distributions Per General Partnership Unit Outstanding									$ 0.425									$ 0.489

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Financial Instruments - Fair Value of Other Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
2013 Senior Notes [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	$ 0	[1]	$ 550,000	[1]
2013 Senior Notes [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	0	[1]	555,500	[1]
2016 Notes [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	1,647,113		1,642,418	[1]
2016 Notes [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	1,824,177		1,650,630	[1]
2020 Notes [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	420,000	[1]	0	[1]
2020 Notes [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	437,850		0	[1]
Liquefaction Credit Facility [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	100,000	[1]	0	[1]
Liquefaction Credit Facility [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Lines of Credit, Fair Value Disclosure	$ 100,000	[1]	$ 0	[1]

[1] The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on December 31, 2012 and 2011, as applicable.

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Financial Instruments - Fair Value and Settlements of Derivatives (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	$ 58,000	$ (2,251,000)	$ 461,000
Collateral deposited	900,000	800,000
Fuel Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	(622,000)
LNG Inventory Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net			0
Cheniere Marketing, LLC [Member] | LNG Lease Agreement [Member] | LNG Inventory Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	$ 1,036,000	$ 2,300,000

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Schedule I - Condensed Financial Information of Registrant - Condensed Balance Sheet (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Nov. 30, 2011	Dec. 31, 2010	Dec. 31, 2009
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	$ 419,292	$ 81,415		$ 53,349	$ 117,542
Advances to affiliate	4,987	692
Prepaid expenses and other	6,652	7,976
Total current assets	532,544	109,510
Other	17,465	13,358
Total assets	3,748,278	1,737,300
Current liabilities	155,410	51,818
Commitments and contingencies
Stockholders' equity (deficit)	1,362,808	(545,019)		(536,008)	(480,327)
Total liabilities and stockholders’ deficit	3,748,278		1,737,300
Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	392,945	56,119		26,482	130
Advances to affiliate	0	136
Prepaid expenses and other	134	135
Total current assets	393,079	56,390
Investment in affiliates	972,395	0
Non-current receivable—affiliates	940	47,238
Other	874	0
Total assets	1,367,288	103,628
Current liabilities	4,480	3,806
Equity in losses of affiliates	0	644,841
Stockholders' equity (deficit)		(545,019)
Total liabilities and stockholders’ deficit	$ 1,367,288	$ 103,628

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Accrued Liabilities Accrued Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Payables and Accruals [Abstract]
Interest and related debt fees	$ 16,327	$ 13,732
Affiliate	5,791	3,794
LNG liquefaction costs	26,131	1,635
LNG terminal costs	977	1,122
Other	3,968	262
Total accrued liabilities (including affiliate)	$ 53,194	$ 20,545

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Financial Instruments - Fair Value of Derivative Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]
Interest Rate Derivatives liability		$ 0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Derivatives, Fair Value [Line Items]
LNG Inventory Derivative assets	0	0
Fuel Derivatives liability	0	0
Interest Rate Derivatives liability	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Derivatives, Fair Value [Line Items]
Interest Rate Derivatives liability	26,424	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Derivatives, Fair Value [Line Items]
LNG Inventory Derivative assets	0	0
Fuel Derivatives liability	0	0
Interest Rate Derivatives liability	0	0
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Derivatives, Fair Value [Line Items]
LNG Inventory Derivative assets	232	1,610
Fuel Derivatives liability	98	1,415
Interest Rate Derivatives liability	26,424	0
Prepaid Expenses And Other [Member] | Cheniere Marketing, LLC [Member] | LNG Lease Agreement [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Derivatives, Fair Value [Line Items]
LNG Inventory Derivative assets	232	1,610
Other Current Liabilities [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Derivatives, Fair Value [Line Items]
Fuel Derivatives liability	$ 98	$ 1,415

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Long-Term Debt Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Schedule of Long-term debt

As of December 31, 2012 and 2011, our long-term debt consisted of the following (in thousands):

	December 31,
	2012			2011
Long-term debt
2013 Notes	$	—		$	550,000
2016 Notes	1,665,500			1,665,500
2020 Notes	420,000			—
Liquefaction Credit Facility	100,000			—
Total long-term, debt	2,185,500			2,215,500
Long-term debt discount
2016 Notes	(18,387		)	(23,082		)
Total long-term debt, net of discount	$	2,167,113		$	2,192,418

Schedule of Maturities of Long-term Debt

Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2012 (in thousands): 

	Payments Due for the Years Ended December 31,
	Total		2013		2014 to 2015		2016 to 2017		Thereafter
Debt (including related parties):
2016 Notes	$	1,665,500	$	—	$	—	$	1,665,500	$	—
2020 Notes	420,000		—		—		—		420,000
Liquefaction Credit Facility	100,000		—		—		—		100,000
Debt (including related parties)	$	2,185,500	$	—	$	—	$	1,665,500	$	520,000

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Long-Term Debt - Schedule of Long-term Debt (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Total long term debt (including related parties)	$ 2,185,500	$ 2,215,500
Long-term Debt	2,167,113	2,192,418
2013 Senior Notes [Member]
Debt Instrument [Line Items]
Total long term debt (including related parties)	0	550,000
2016 Notes [Member]
Debt Instrument [Line Items]
Total long term debt (including related parties)	1,665,500	1,665,500
Debt Instrument, Unamortized Discount	(18,387)	(23,082)
2020 Notes [Member]
Debt Instrument [Line Items]
Total long term debt (including related parties)	420,000	0
Liquefaction Credit Facility [Member]
Debt Instrument [Line Items]
Total long term debt (including related parties)	$ 100,000	$ 0

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Schedule I - Condensed Financial Information of Registrant - Condensed Statements of Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Condensed Financial Statements, Captions [Line Items]
Revenues	$ 67,300	$ 66,308	$ 61,396	$ 69,323	$ 70,824	$ 64,907	$ 73,609	$ 74,450	$ 264,327	$ 283,790	$ 399,282
Operating costs and expenses									35,457	21,827	27,069
Interest expense, net									171,646	173,590	174,016
Net income (loss)	(63,521)	(42,422)	(24,861)	(19,332)	(7,463)	(14,479)	(6,868)	(2,209)	(150,136)	(31,019)	107,568
Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Revenues									0	0	0
Operating costs and expenses									18,262	13,104	14,723
Loss from operations									(18,262)	(13,104)	(14,723)
Interest expense, net									12	0	0
Interest income									235	38	51
Equity income (loss) of affiliates									(132,121)	(17,953)	122,240
Net income (loss)										$ (31,019)	$ 107,568

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Subsequent Events

12 Months Ended

Dec. 31, 2012

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

Sabine Liquefaction Notes

In February 2013, Sabine Pass Liquefaction issued an aggregate principal amount of $1.5 billion of 5.625% Senior Secured Notes due 2021 (the "Sabine Liquefaction Notes"). Net proceeds from the offering are intended to be used to pay capital costs incurred in connection with the construction of Train 1 and Train 2 of the Liquefaction Project in lieu of a portion of the commitments under the Liquefaction Credit Facility.

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Financial Instruments - Fair Value of Interest Rate Derivatives by Balance Sheet Location (Details) (Interest Rate Contract [Member], Non-current Liabilities [Member], USD $)	Dec. 31, 2012	Dec. 31, 2011
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	$ 21,290,000	$ 0
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	$ 5,134,000	$ 0

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LNG Inventory and LNG Inventory - Affiliate (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
LNG Inventory And LNG Inventory - Affiliate [Abstract]
LNG inventory	$ 2,625,000	$ 473,000
Inventory LCM adjustments recognized	9,400,000	400,000	300,000
LNG inventory related party	4,420,000	4,369,000
LNG inventory related party LCM adjustments recognized	$ 11,000,000	$ 10,600,000	$ 0

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Supplemental Information to Consolidated Combined Financial Statements (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

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

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2012:
Revenues	$	69,323		$	61,396		$	66,308		67,300
Income from operations	24,891			18,275			772			19,602
Net loss	(19,332		)	(24,861		)	(42,422		)	(63,521		)
Net income (loss) per common unit—basic and diluted	$	0.23		$	0.17		$	0.04		$	(0.06	)
Year ended December 31, 2011:
Revenues	$	74,450		$	73,609		$	64,907		$	70,824
Income from operations	41,127			36,932			29,523			37,044
Net loss	(2,209		)	(6,868		)	(14,479		)	(7,463		)
Net income per common unit—basic and diluted	$	0.35		$	0.32		$	0.29		$	0.30

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Financial Instruments - Changes in Fair Value of De-Designated Interest Rate Derivatives (Details) (Not Designated as Hedging Instrument [Member], Interest Rate Contract [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Increase (Decrease) in Fair Value of Derivative Instruments, Not Designated as Hedging Instruments	$ 679	$ 0	$ 0

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Cash Distributions and Net Income (Loss) per Common Unit (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	$ (63,521)	$ (42,422)	$ (24,861)	$ (19,332)	$ (7,463)	$ (14,479)	$ (6,868)	$ (2,209)	$ (150,136)	$ (31,019)	$ 107,568
Declared distributions									61,501	50,136	104,538
Amortization ofbeneficial conversion feature of Class B units									0
Assumed allocation of undistributed net loss									(211,637)	(81,155)	3,030
Weighted average units outstanding										27,910	26,416
Net income (loss) per common unit	$ (0.06)	$ 0.04	$ 0.17	$ 0.23	$ 0.30	$ 0.29	$ 0.32	$ 0.35		$ 1.23	$ 1.70
Subordinated Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss									(114,678)	(25,301)	88,206
Declared distributions									0	0	57,538
Amortization ofbeneficial conversion feature of Class B units									(20,170)
Assumed allocation of undistributed net loss									(157,917)	(64,713)	2,969
Assumed allocation of net income (loss)									(178,087)	(64,713)	60,507
Weighted average units outstanding									135,384	135,384	135,384
Net income (loss) per common unit									$ (1.32)	$ (0.48)	$ 0.45
Class B Unit [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Declared distributions									0	0	0
Amortization ofbeneficial conversion feature of Class B units									25,319
Assumed allocation of undistributed net loss									0	0	0
Assumed allocation of net income (loss)									25,319	0	0
Weighted average units outstanding									43,303	0	0
Net income (loss) per common unit									$ 0.58	$ 0.00	$ 0.00
General Partner [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss									(7,107)	(620)	2,151
Declared distributions									1,230	1,002	2,090
Amortization ofbeneficial conversion feature of Class B units									0
Assumed allocation of undistributed net loss									(7,659)	(1,623)	61
Assumed allocation of net income (loss)									(6,429)	(621)	2,151
Common Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss									(28,351)	(5,098)	17,211
Declared distributions									60,271	49,134	44,910
Amortization ofbeneficial conversion feature of Class B units									(5,149)
Assumed allocation of undistributed net loss									(46,061)	(14,819)	0
Assumed allocation of net income (loss)									$ 9,061	$ 34,315	$ 44,910
Weighted average units outstanding									33,470	27,910	26,416
Net income (loss) per common unit									$ 0.27	$ 1.23	$ 1.70

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Related Party Transactions (Details) (USD $)	12 Months Ended											12 Months Ended	1 Months Ended	12 Months Ended								1 Months Ended	12 Months Ended					12 Months Ended					12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 Sabine Pass LNG, LP [Member]	Dec. 31, 2010 Sabine Pass LNG, LP [Member]	Dec. 31, 2012 LNG Lease Agreement [Member] Cheniere Marketing, LLC [Member] MMBTU	Dec. 31, 2011 LNG Lease Agreement [Member] Cheniere Marketing, LLC [Member] MMBTU	Dec. 31, 2012 Service Agreements [Member]	Dec. 31, 2011 Service Agreements [Member]	Dec. 31, 2010 Service Agreements [Member]	Dec. 31, 2012 Operation and Maintenance Agreement [Member] Sabine Pass LNG, LP [Member]	Dec. 31, 2012 Operation and Maintenance Agreement [Member] Sabine Pass Liquefaction [Member]	May 31, 2012 Management Services Agreement [Member] Sabine Pass Liquefaction [Member]	Dec. 31, 2011 Contracts for Sale and Purchase of Natural Gas and LNG [Member] Natural Gas [Member] Sabine Pass LNG, LP [Member]	Dec. 31, 2010 Contracts for Sale and Purchase of Natural Gas and LNG [Member] Natural Gas [Member] Sabine Pass LNG, LP [Member]	Dec. 31, 2012 Contracts for Sale and Purchase of Natural Gas and LNG [Member] Natural Gas And Liquefied Natural Gas [Member] Sabine Pass LNG, LP [Member]	Dec. 31, 2011 Contracts for Sale and Purchase of Natural Gas and LNG [Member] Natural Gas And Liquefied Natural Gas [Member] Sabine Pass LNG, LP [Member]	Dec. 31, 2010 Contracts for Sale and Purchase of Natural Gas and LNG [Member] Natural Gas And Liquefied Natural Gas [Member] Sabine Pass LNG, LP [Member]	Dec. 31, 2012 LNG Terminal Export Agreement [Member] Sabine Pass LNG and Cheniere Partners [Member]	Dec. 31, 2011 LNG Terminal Export Agreement [Member] Sabine Pass LNG and Cheniere Partners [Member]	Dec. 31, 2010 LNG Terminal Export Agreement [Member] Sabine Pass LNG and Cheniere Partners [Member]	Jul. 31, 2010 LNG Terminal Capacity Agreements [Member]	Dec. 31, 2012 LNG Terminal Capacity Agreements [Member]	Dec. 31, 2012 LNG Terminal Capacity Agreements [Member] Cheniere Marketing, LLC [Member] MMBTU	Dec. 31, 2011 LNG Terminal Capacity Agreements [Member] Cheniere Marketing, LLC [Member]	Dec. 31, 2010 LNG Terminal Capacity Agreements [Member] Cheniere Marketing, LLC [Member]	Nov. 30, 2006 LNG Terminal Capacity Agreements [Member] Cheniere Marketing, LLC [Member]	Dec. 31, 2012 Tug Boat Lease Sharing Agreement [Member] Sabine Pass LNG, LP [Member]	Dec. 31, 2012 Profit Category One [Member] LNG Terminal Capacity Agreements [Member] MMBTU	Dec. 31, 2012 Profit Category Two [Member] LNG Terminal Capacity Agreements [Member] MMBTU	Dec. 31, 2012 Fair Value, Measurements, Recurring [Member] Prepaid Expenses And Other [Member] Fair Value, Inputs, Level 2 [Member] LNG Lease Agreement [Member] Cheniere Marketing, LLC [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member] Prepaid Expenses And Other [Member] Fair Value, Inputs, Level 2 [Member] LNG Lease Agreement [Member] Cheniere Marketing, LLC [Member]	Dec. 31, 2010 LNG Inventory Derivatives [Member]	Dec. 31, 2012 LNG Inventory Derivatives [Member] LNG Lease Agreement [Member] Cheniere Marketing, LLC [Member]	Dec. 31, 2011 LNG Inventory Derivatives [Member] LNG Lease Agreement [Member] Cheniere Marketing, LLC [Member]	Dec. 31, 2012 Cooperative Endeavor Agreements [Member]	Dec. 31, 2011 Cooperative Endeavor Agreements [Member]	Jul. 31, 2007 Cooperative Endeavor Agreements [Member]
Related Party Transaction [Line Items]
Advances to Affiliate Current	$ 4,987,000	$ 692,000
Regasification capacity	4																										2.0
Related Party Transactions, Commitments, Annual Reservation Fee Payment																							250,000,000
Proceeds (Payments) of Gross Margin Earned, Percentage																						80.00%								20.00%
Revenues—affiliate	7,973,000	14,607,000	130,954,000	2,700,000	2,700,000									0	0			2,800,000	300,000	300,000	900,000			4,900,000	11,200,000	1,900,000		2,800,000
Purchase Commitment, Excess And Uncommitted LNG Produced																								104,000,000					36,000,000	68,000,000
Incremental LNG Volume, Purchase Price Percentage																													115.00%
Incremental LNG Volume, Purchase Price Per MMBtu																													3
Liquefied Natural Gas Inventory						1,369,000	1,527,000
LNG inventory related party	4,420,000	4,369,000					4,400,000
LNG inventory related party LCM adjustments recognized	11,000,000	10,600,000	0			1,400,000	11,400,000
LNG Inventory Derivative assets																															232,000	1,610,000
Derivative gain (loss), net	58,000	(2,251,000)	461,000																														0	1,036,000	2,300,000
General and Administrative Expense Related Parties	55,940,000	20,469,000	20,275,000					53,500,000	19,000,000	15,900,000
Related Party Transaction, Committed Monthly Fee											130,000	83,333	541,667
Related Party Transaction, Bonus Percentage Entitled Upon Meeting Certain Criteria											50.00%
Proceeds (Payments) Of Capital Expenditures Incurred												0.60%	2.40%
Aggregate commitment under the Agreement																																				25,000,000		25,000,000
Deferred Revenue Related Party Current	696,000	688,000																																		14,700,000	12,300,000
Related Party Transaction, Purchases from Related Party																$ 2,800,000	$ 4,200,000

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Financial Instruments - Fair Value of Financial Instruments by Balance Sheet Location (Details) (Fair Value, Measurements, Recurring [Member], Fair Value, Inputs, Level 2 [Member], USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fuel Derivatives liability	$ 98	$ 1,415
LNG Lease Agreement [Member] | Cheniere Marketing, LLC [Member] | Prepaid Expenses And Other [Member]
Derivatives, Fair Value [Line Items]
LNG Inventory Derivative assets	$ 232	$ 1,610

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Initial Public Offering

12 Months Ended

Dec. 31, 2012

INITIAL PUBLIC OFFERING [Abstract]

Initial Public Offering

INITIAL PUBLIC OFFERING

We and Holdings, as a selling unitholder, completed an offering of 13,500,000 Cheniere Partners common units for $21.00 per common unit on March 26, 2007 (the "Cheniere Partners Offering"). Upon the closing of the Cheniere Partners Offering, the following transactions occurred: 

• Holdings contributed through us to our wholly owned subsidiary, Cheniere Energy Investments, LLC ("Cheniere Investments"), all of its equity interests in Sabine Pass LNG-GP, LLC ("Sabine Pass GP") and Sabine Pass LNG-LP, LLC ("Sabine Pass LP"), which own all of the equity interests in Sabine Pass LNG, the owner of the entire interest in the Sabine Pass LNG terminal; 

• we issued to Holdings 21,362,193 common units and 135,383,831 subordinated units; 

• we issued to our general partner, a direct wholly owned subsidiary of Holdings, 3,302,045 general partner units representing a 2% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash that we distribute in excess of $0.489 per unit per quarter; 

• we issued 5,054,164 common units to the public in the Cheniere Partners Offering; 

• Holdings sold 8,445,836 common units to the public in the Cheniere Partners Offering, after which Holdings and the public held an aggregate 89.8% and 8.2% limited partner interest in us, respectively; 

• our general partner entered into a services agreement with an affiliate of Cheniere under which the affiliate provides various general and administrative services for an annual administrative fee of $10.0 million (adjusted for inflation after January 1, 2007), with payment having commenced January 1, 2009; provided that the fee is currently structured as a non-accountable overhead reimbursement charge of $2.8 million per quarter (indexed for inflation); and 

• we entered into a services and secondment agreement with an affiliate of Cheniere pursuant to which certain employees of the Cheniere affiliate have been seconded to our general partner to provide operating and routine maintenance services with respect to the Sabine Pass LNG terminal.

We received $98.4 million of net proceeds, after deducting the underwriting discount and structuring fee, upon issuance of 5,054,164 common units to the public in the Cheniere Partners Offering. Holdings received $164.5 million of net proceeds, after deducting the underwriting discount and structuring fee, upon its sale of 8,445,836 common units. We did not receive any proceeds from the sale of common units by Holdings. We used all of our net proceeds of $98.4 million from the sale of our common units in the Cheniere Partners Offering to purchase U.S. Treasury securities that funded a distribution reserve for payment of initial quarterly distributions of $0.425 per common unit, as well as related quarterly distributions to our general partner, through the quarterly distribution made in respect of the quarter ended June 30, 2009. Our common units are traded on the NYSE MKT under the symbol "CQP."

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Leases - Schedule of Future Minimum Lease Payments (Details) (USD $)	Dec. 31, 2012
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2013	$ 9,625,000	[1]
2014	9,625,000	[1]
2015	9,604,000	[1]
2016	9,577,000	[1]
2017	9,462,000	[1]
Later years	231,884,000	[1],[2]
Total minimum payments required	279,777,000	[1]
Sublease payments to be received from TUA customers	$ 112,800,000

[1] Lease payments for Sabine Pass LNG’s tug boat lease represent its lease payment obligation and do not take into account the $112.8 million of sublease payments Sabine Pass LNG will receive from its three TUA customers that effectively offset these lease payment obligations, as discussed below. La

[2] Includes certain lease option renewals as they are reasonably assured.

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Property, Plant and Equipment - Capitalized Costs and Fixed Assets (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 2,704,895,000	$ 1,514,416,000
Depreciation expense	42,551,000	42,943,000	42,299,000
LNG terminal costs [Member]
Property, Plant and Equipment [Line Items]
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	(166,538,000)	(124,409,000)
Property, plant and equipment, net	2,703,987,000	1,513,764,000
Depreciation expense	42,100,000	42,600,000	41,800,000
LNG terminal [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,641,722,000	1,637,724,000
LNG terminal construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,228,647,000	286,000
LNG site and related costs, net [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	156,000	163,000
Fixed assets [Member]
Property, Plant and Equipment [Line Items]
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	(2,397,000)	(1,975,000)
Property, plant and equipment, net	908,000	652,000
Computer and Office Equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	368,000	227,000
Vehicles
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	704,000	416,000
Machinery and Equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,473,000	1,068,000
Other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	760,000	916,000
Sabine Pass Liquefaction [Member]
Property, Plant and Equipment [Line Items]
Capitalized interest expense	$ 35,100,000

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Schedule of capitalized terminal costs and fixed assets

Property, plant and equipment consists of LNG terminal costs and fixed assets, as follows (in thousands):

	December 31,
	2012			2011
LNG terminal costs
LNG terminal	$	1,641,722		$	1,637,724
LNG terminal construction-in-process	1,228,647			286
LNG site and related costs, net	156			163
Accumulated depreciation	(166,538		)	(124,409		)
Total LNG terminal costs, net	2,703,987			1,513,764
Fixed assets
Computer and office equipment	368			227
Vehicles	704			416
Machinery and equipment	1,473			1,068
Other	760			916
Accumulated depreciation	(2,397		)	(1,975		)
Total fixed assets, net	908			652
Property, plant and equipment, net	$	2,704,895		$	1,514,416

Schedule of estimated 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
Others	15-30

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Basis of Presentation

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 Partners, L.P. 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

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

Accounting for LNG Activities

Generally, we begin capitalizing the costs of LNG terminal projects 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

Revenue Recognition

LNG regasification capacity reservation fees are recognized as revenue over the term of the respective terminal use agreements ("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.

Derivatives

Derivatives

We use derivative instruments from time to time to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory, to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal, and to hedge the exposure to volatility in a portion of the floating-rate interest payments under the Liquefaction Credit Facility. We do not offset the fair value amounts of our LNG inventory, fuel and interest rate derivatives, and collateral deposited for such contracts are not netted within the derivative fair value.  We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 8—"Financial Instruments" of our Notes to Consolidated Financial Statements.

Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. We record changes in the fair value of our derivative positions 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 and interest rates change.

Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are recognized currently in earnings. Gains and losses in positions to hedge the cash flows attributable to the future sale of LNG inventory are classified as 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 have elected cash flow hedge accounting for derivatives that we use to hedge the exposure to volatility in floating-rate interest payments. Changes in fair value of derivative instruments designated as cash flow hedges, to the extent the hedge is effective, are recognized in accumulated other comprehensive loss on our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive loss into interest expense in our Consolidated Statements of Operations as the hedged item is recognized. Any change in the fair value resulting from ineffectiveness is recognized immediately as derivative gain (loss) on our Consolidated Statements of Operations. We use regression analysis to determine whether we expect a derivative to be highly effective as a cash flow hedge prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges have been effective. We perform these effectiveness tests prior to designation for all new hedges and on a quarterly basis for all existing hedges. We calculate the actual amount of ineffectiveness on our cash flow hedges using the "dollar offset" method, which compares changes in the expected cash flows of the hedged transaction to changes in the value of expected cash flows from the hedge. We discontinue hedge accounting when our effectiveness tests indicate that a derivative is no longer highly effective as a hedge; when the derivative expires or is sold, terminated or exercised; when the hedged item matures, is sold or repaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but continue to hold the derivative, we begin to apply mark-to-market accounting at that time.

Fair Value of Financial Instruments

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

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.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded as an other current asset and not netted within the derivative fair value. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

Sabine Pass LNG has entered into certain long-term TUAs with unaffiliated third parties for regasification capacity at our Sabine Pass LNG terminal. We are dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective TUAs. We have mitigated this credit risk by securing TUAs for a significant portion of our regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA.

Property, Plant and Equipment

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 property, plant and equipment for 2012, 2011 or 2010.

Income Taxes

Income Taxes

We are not subject to either federal or state income taxes, as the partners are taxed individually on their proportionate share of our earnings. At December 31, 2012, the tax basis of our assets and liabilities was $290.6 million less than the reported amounts of our assets and liabilities.

In November 2006, Sabine Pass LNG and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass LNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass LNG will pay to Cheniere an amount equal to the state and local tax that Sabine Pass LNG would be required to pay if Sabine Pass LNG's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass LNG under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass LNG. The agreement is effective for tax returns due on or after January 1, 2008.

In August 2012, Sabine Pass Liquefaction and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass Liquefaction and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass Liquefaction will pay to Cheniere an amount equal to the state and local tax that Sabine Pass Liquefaction would be required to pay if Sabine Pass Liquefaction's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass Liquefaction under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass Liquefaction. The agreement is effective for tax returns due on or after August 2012.

Use of Estimates

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 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 units, reduced estimates of future cash flows for our business 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, 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, valuations of derivative instruments 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.

Debt Issuance Costs

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.

Asset Retirement Obligations

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:

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. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is zero. Therefore, we have not recorded an asset retirement obligation associated with the Sabine Pass LNG terminal.

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Deferred Revenue Deferred Revenue (Details) (USD $)										1 Months Ended					1 Months Ended	3 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 TUA Payments [Member]	Dec. 31, 2011 TUA Payments [Member]	Dec. 31, 2012 Cooperative Endeavor Agreements [Member]	Dec. 31, 2011 Cooperative Endeavor Agreements [Member]	Jul. 31, 2007 Cooperative Endeavor Agreements [Member]	Dec. 31, 2012 Total Gas and Power North America, Inc. [Member]	Dec. 31, 2011 Total Gas and Power North America, Inc. [Member]	Apr. 30, 2009 Total Gas and Power North America, Inc. [Member] Advance Capacity Reservation Fee [Member]	Apr. 30, 2005 Total Gas and Power North America, Inc. [Member] Advance Capacity Reservation Fee [Member]	Nov. 30, 2004 Total Gas and Power North America, Inc. [Member] Advance Capacity Reservation Fee [Member]	Dec. 31, 2012 Chevron U.S.A. Inc. [Member]	Dec. 31, 2011 Chevron U.S.A. Inc. [Member]	Dec. 31, 2005 Chevron U.S.A. Inc. [Member] Advance Capacity Reservation Fee [Member]	Jun. 30, 2009 Chevron U.S.A. Inc. [Member] Advance Capacity Reservation Fee [Member]	Nov. 30, 2004 Chevron U.S.A. Inc. [Member] Advance Capacity Reservation Fee [Member]
Deferred Revenue Arrangement [Line Items]
Advance Payments Netted Against Claim Receivable											$ 10,000,000	$ 10,000,000			$ 20,000,000
Regasification capacity	4											1.0			1.0		0.7
Increase in regassification capacity															0.3
Advanced capacity reservation fees amortization period										10 years						10 years
Current deferred revenue	26,540,000	26,629,000	21,100,000	21,100,000				4,000,000	4,000,000
Non-current deferred revenue	21,500,000	25,500,000											21,500,000	25,500,000
Aggregate commitment under the Cooperative Endeavor Agreement					25,000,000		25,000,000
Other non-current assets and non-current deferred revenue	$ 696,000	$ 688,000	$ 0	$ 0	$ 14,700,000	$ 12,300,000

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Property, Plant and Equipment - Estimated Useful Lives (Details)	12 Months Ended
	Dec. 31, 2012
Minimum [Member]
Property, Plant and Equipment [Line Items]
Useful life	15 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Useful life	50 years
LNG storage tanks [Member]
Property, Plant and Equipment [Line Items]
Useful life	50 years
Marine berth, electrical, facility and roads [Member]
Property, Plant and Equipment [Line Items]
Useful life	35 years
Regasification processing equipment (recondensers, vaporization, and vents) [Member]
Property, Plant and Equipment [Line Items]
Useful life	30 years
Sendout pumps [Member]
Property, Plant and Equipment [Line Items]
Useful life	20 years
Other | Minimum [Member]
Property, Plant and Equipment [Line Items]
Useful life	15 years
Other | Maximum [Member]
Property, Plant and Equipment [Line Items]
Useful life	30 years

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Debt Issuance Costs Debt Issuance Costs (Tables)

12 Months Ended

Dec. 31, 2012

DEBT ISSUANCE COSTS [Abstract]

Schedule of Debt Issuance Costs

As of December 31, 2012, we had capitalized $220.9 million of costs directly associated with the arrangement of debt financing, net of accumulated amortization, as follows (in thousands): 

Long-Term Debt	Debt Issuance Costs		Amortization Period	Accumulated Amortization			Net Costs
Liquefaction Credit Facility	$	212,795	7 years	$	(12,728	)	$	200,067
2016 Notes	30,057		10 years	(18,030		)	12,027
2020 Notes	9,092		8 years	(237		)	8,855
Total	$	251,944		$	(30,995	)	$	220,949

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Financial Instruments Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following table (in thousands) shows the fair value of our derivative assets and liabilities that are required to be measured at fair value on a recurring basis as of December 31, 2012 and 2011, which are classified as other current assets, other current liabilities and other non-current liabilities in our Consolidated Balance Sheets.

	Fair Value Measurements as of
	December 31, 2012								December 31, 2011
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
LNG Inventory Derivatives asset	$	—	$	232	$	—	$	232	$	—	$	1,610	$	—	$	1,610
Fuel Derivatives liability	—		98		—		98		—		1,415		—		1,415
Interest Rate Derivatives liability	—		26,424		—		26,424		—		—		—		—

Fair Value, by Balance Sheet Grouping

Other Financial Instruments (in thousands):

	December 31, 2012				December 31, 2011
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2013 Notes (1)	$	—	$	—	$	550,000	$	555,500
2016 Notes, net of discount (1)	1,647,113		1,824,177		1,642,418		1,650,630
2020 Notes (1)	420,000		437,850		—		—
Liquefaction Credit Facility (2)	100,000		100,000		—		—

(1) The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on December 31, 2012 and 2011, as applicable.

(2) The Level 3 estimated fair value of the Liquefaction Credit Facility as of December 31, 2012 was determined to be the carrying amount due to our ability to call this debt at anytime without penalty. 

The following table (in thousands) shows the fair value and location of our LNG Inventory Derivatives and Fuel Derivatives on our Consolidated Balance Sheets:

		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2012		December 31, 2011
LNG Inventory Derivatives asset	Prepaid expenses and other	$	232	$	1,610
Fuel Derivatives liability	Other current liabilities	98		1,415

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

The following table (in thousands) shows the changes in the fair value of our De-designated Interest Rate Derivatives recorded in derivative gain on our Consolidated Statements of Operations during the years endedDecember 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
Interest Rate Derivatives - De-designated	$	679	$	—	$	—

The following table (in thousands) shows the changes in the fair value and settlements of our LNG Inventory Derivatives recorded in marketing and trading revenues (losses) on our Consolidated Statements of Operations during the years endedDecember 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
LNG Inventory Derivatives gain	$	1,036	$	2,300	$	—

The following table (in thousands) shows the changes in the fair value and settlements of our Fuel Derivatives recorded in derivative gain (loss) on our Consolidated Statements of Operations during the years endedDecember 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
Fuel Derivatives gain (loss)	$	(622	)	$	(2,251	)	$	461

Schedule of Notional Amounts of Outstanding Derivative Positions

At December 31, 2012, Sabine Pass Liquefaction had the following Interest Rate Derivatives outstanding that converted $20.0 million of the Liquefaction Credit Facility from a variable to a fixed interest rate. Sabine Pass Liquefaction pays a fixed interest rate on the swap and in exchange receives a variable interest rate based on the one-month LIBOR.

	Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
Interest Rate Derivatives - Designated	$16.1 million	$2.3 billion	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR
Interest Rate Derivatives - De-designated	$3.9 million	$575.3 million	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR

Schedule of Interest Rate Derivatives

The following table (in thousands) shows the fair value of our interest rate swaps:

		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2012		December 31, 2011
Interest Rate Derivatives - Designated	Non-current derivative liabilities	$	21,290	$	—
Interest Rate Derivatives - De-designated	Non-current derivative liabilities	5,134		—

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)

The following table (in thousands) shows our Interest Rate Derivatives market adjustments recorded during the year endedDecember 31, 2012:

	Gain (Loss) in Other Comprehensive Income					Gain (Loss) Reclassified from Accumulated OCI into Interest Expense (Effective Portion)				Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	2012			2011		2012		2011		2012		2011
Interest Rate Derivatives - Designated	$	(21,290	)	$	—	$	—	$	—	$	—	$	—
Interest Rate Derivatives - De-designated	(5,814		)	—		—		—		—		—
Interest Rate Derivatives - Settlements	(136		)	—		—		—		—		—

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The Company's commodity and interest rate derivatives are presented on a net basis on our Consolidated Balance Sheets as described above. The following table (in thousands) shows the fair value of our derivatives outstanding on a gross basis:

	December 31, 2012		December 31, 2011
Commodity Derivatives:
Assets	$	607	$	1,942
Liabilities	474		1,747
Interest Rate Derivatives:
Assets - designated	$	17,512	$	—
Assets - de-designated	4,283		—
Liabilities - designated	38,729		—
Liabilities - de-designated	9,491		—

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Nature of Operations

12 Months Ended

Dec. 31, 2012

NATURE OF OPERATIONS [Abstract]

Nature of Operations

NATURE OF OPERATIONS

Cheniere Energy Partners, L.P. ("Cheniere Partners") is a publicly-held Delaware limited partnership formed on November 21, 2006. As of December 31, 2012, Cheniere Energy, Inc. ("Cheniere") owned 59.5% of the limited partnership through its wholly owned subsidiaries, Cheniere LNG Holdings, LLC ("Holdings"), Cheniere Common Units Holding, LLC ("Cheniere Common Units Holding"), Cheniere Subsidiary Holdings, LLC ("Subsidiary Holdings") and Cheniere Energy Partners GP, LLC ("Cheniere GP"). Cheniere Partners was formed to own and operate the Sabine Pass liquefied natural gas ("LNG") terminal located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNG terminal has regasification facilities owned by our wholly owned subsidiary, Sabine Pass LNG, L.P. ("Sabine Pass LNG") that includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels of up to 265,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Approximately one-half of the receiving capacity at the Sabine Pass LNG terminal is contracted to two multinational energy companies.

We are developing natural gas liquefaction facilities (the "Liquefaction Project") at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction". We plan to construct up to six Trains (each in sequence, "Train 1", "Train 2", "Train 3", "Train 4", "Train 5" and "Train 6"), which are in various stages of development. Each Train has a nominal production capacity of approximately 4.5 mmtpa.

Unless the context requires otherwise, references to "Cheniere Partners", "we", "us" and "our" refer to Cheniere Partners and its subsidiaries.

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Accrued Liabilities Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2012

Payables and Accruals [Abstract]

Schedule of Accrued Liabilities [Table Text Block]

As of December 31, 2012 and 2011, accrued liabilities consisted of the following (in thousands):

	December 31,
	2012		2011
Interest and related debt fees	$	16,327	$	13,732
Affiliate	5,791		3,794
LNG liquefaction costs	26,131		1,635
LNG terminal costs	977		1,122
Other	3,968		262
Total accrued liabilities (including affiliate)	$	53,194	$	20,545

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Summary of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Accounting Policies [Abstract]
Retained percentage of LNG delivered	2.00%
Difference in tax basis of assets and liabilities	$ 290.6
Maximum term of property leases	90 years

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Financial Instruments - Derivative Gross Presentation on Consolidated Balance Sheets (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Commodity Contract [Member]
Derivative [Line Items]
Derivative Assets	$ 607	$ 1,942
Derivative Liabilities	474	1,747
Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Assets	17,512	0
Derivative Liabilities		0
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Assets	4,283	0
Derivative Liabilities	9,491	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Liabilities	$ 38,729

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Schedule I - Condensed Financial Information of Registrant - Condensed Statements of Cash Flows (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Condensed Financial Statements, Captions [Line Items]
Cash flows from operating activities	$ (26,214)	$ 14,249	$ 104,137
Other	740	1,054	121
Net cash used in investing activities	(4,455)	(8,191)	(5,076)
Distributions to owners	(57,821)	(48,149)	(163,249)
Proceeds from sale of partnership units	250,022	70,157	0
Net cash provided by financing activities	368,546	22,008	(163,254)
Net increase in cash and cash equivalents	337,877	28,066	(64,193)
Cash and cash equivalents—beginning of period	81,415	53,349	117,542
Cash and cash equivalents—end of period	419,292	81,415	53,349
Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Cash flows from operating activities	(17,508)	(13,948)	(10,193)
Investment in subsidiaries	(1,832,440)	0	(20,918)
Other	3	0	0
Net cash used in investing activities	(1,832,437)	0	(20,918)
Proceeds from sale of Class B units	1,887,342	0	0
Distributions (to) received from affiliates, net	61,529	59,910	229,608
Distributions to owners	(57,821)	(48,149)	(163,249)
Proceeds from sale of partnership units	250,021	70,157	0
Affiliate receivable	46,574	(38,333)	(8,896)
Borrowings under long-term note—affiliate	(874)	0	0
Net cash provided by financing activities	2,186,771	43,585	57,463
Net increase in cash and cash equivalents	336,826	29,637	26,352
Cash and cash equivalents—beginning of period	56,119	26,482	130
Cash and cash equivalents—end of period	$ 392,945	$ 56,119	$ 26,482

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current assets
Cash and cash equivalents	$ 419,292	$ 81,415
Restricted cash and cash equivalents	92,519	13,732
Accounts and interest receivable	44	525
Accounts receivable—affiliate	2,005	328
Advances to Affiliate Current	4,987	692
LNG inventory	2,625	473
LNG inventory related party	4,420	4,369
Prepaid expenses and other	6,652	7,976
Total current assets	532,544	109,510
Non-current restricted cash and cash equivalents	272,425	82,394
Property, plant and equipment, net	2,704,895	1,514,416
Debt issuance costs, net	220,949	17,622
Other	17,465	13,358
Total assets	3,748,278	1,737,300
Current liabilities
Accounts payable	73,760	704
Accounts payable—affiliate	1,122	530
Accrued liabilities	47,403	16,751
Accrued liabilities—affiliate	5,791	3,794
Deferred revenue	26,540	26,629
Deferred Revenue Related Party Current	696	688
Other	98	2,722
Total current liabilities	155,410	51,818
Long-term debt, net of discount	2,167,113	2,192,418
Deferred revenue	21,500	25,500
Deferred Revenue Related Party Noncurrent	14,720	12,266
Derivative Liabilities, Noncurrent		0
Other non-current liabilities	303	317
Commitments and contingencies
Partners' deficit
Common Unitholders Equity (31,003,154 and 26,416,357 units issued and outstanding at December 31, 2011 and 2010, respectively)		(52,774)
Limited Partners' Capital Account		0
Subordinated Unitholders Equity (135,383,831 units issued and outstanding at December 31, 2011 and 2010)	949,482	(479,197)
General partner interest (2% interest with 3,395,653 units and 3,302,045 units issued and outstanding at December 31, 2011 and 2010, respectively)	29,496	(13,048)
Accumulated Other Comprehensive Income (Loss), Net of Tax		0
Total partners' deficit	1,362,808	(545,019)
Total liabilities and partners' deficit	$ 3,748,278

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Debt Issuance Costs Debt Issuance Costs (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Debt issuance costs, gross	$ 251,944
Accumulated amortization	(30,995)
Debt issuance costs, net	220,949
Unamortized Debt Issuance Expense	220,949	17,622
Liquefaction Credit Facility [Member]
Debt Instrument [Line Items]
Debt issuance costs, gross	212,795
Amortization period	7 years
Accumulated amortization	(12,728)
Debt issuance costs, net	200,067
2016 Notes [Member]
Debt Instrument [Line Items]
Debt issuance costs, gross	30,057
Amortization period	10 years
Accumulated amortization	(18,030)
Debt issuance costs, net	12,027
2020 Notes [Member]
Debt Instrument [Line Items]
Debt issuance costs, gross	9,092
Amortization period	8 years
Accumulated amortization	(237)
Debt issuance costs, net	$ 8,855

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Consolidated Statements of Partners' and Owners' Capital (Deficit) (USD $) In Thousands, unless otherwise specified	Total	Common Units	Class B Unit [Member]	Subordinated Units	General Partner Units	Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax at Dec. 31, 2009						$ 0
General Partners' Capital Account at Dec. 31, 2009					(11,807)
Partners' Capital Beginning of Period at Dec. 31, 2009	(480,327)
Limited Partners' Capital Account at Dec. 31, 2009			0
Common Unitholders Equity at Dec. 31, 2009		(41,494)
Subordinated Unitholders Equity at Dec. 31, 2009				(427,026)
Increase (Decrease) in Stockholders' Equity
Net income (loss)	107,568	17,211		88,206	2,151
Distributions	(163,249)	(44,908)		(115,076)	(3,265)
Accumulated Other Comprehensive Income (Loss), Net of Tax at Dec. 31, 2010						0
General Partners' Capital Account at Dec. 31, 2010					(12,921)
Partners' Capital End of Period at Dec. 31, 2010	(536,008)
Limited Partners' Capital Account at Dec. 31, 2010			0
Common Unitholders Equity at Dec. 31, 2010		(69,191)
Subordinated Unitholders Equity at Dec. 31, 2010				(453,896)
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(31,019)	(5,098)		(25,301)	(620)
Common Units Sold	70,157	68,701			1,456
Distributions	(48,149)	(47,186)			(963)
Accumulated Other Comprehensive Income (Loss), Net of Tax at Dec. 31, 2011	0					0
General Partners' Capital Account at Dec. 31, 2011	(13,048)				(13,048)
Partners' Capital End of Period at Dec. 31, 2011	(545,019)
Limited Partners' Capital Account at Dec. 31, 2011	0		0
Common Unitholders Equity at Dec. 31, 2011	(52,774)	(52,774)
Subordinated Unitholders Equity at Dec. 31, 2011	(479,197)			(479,197)
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(150,136)	(28,351)		(114,678)	(7,107)
Common Units Sold	250,022	204,878			45,144
Distributions	(57,821)	(56,665)			(1,156)
Partners' Capital Account, Contributions	5,663				5,663
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	(27,240)					(27,240)
Partners Capital Account, Sale Of Class B Units	1,887,339		1,887,339
Partners' Capital Account, Exchanges and Conversions		386,473	(1,950,000)	1,563,527
Amortization ofbeneficial conversion feature of Class B units	0	(5,149)	25,319	(20,170)	0
Accumulated Other Comprehensive Income (Loss), Net of Tax at Dec. 31, 2012						(27,240)
General Partners' Capital Account at Dec. 31, 2012	29,496				29,496
Partners' Capital End of Period at Dec. 31, 2012	1,362,808
Limited Partners' Capital Account at Dec. 31, 2012			(37,342)
Common Unitholders Equity at Dec. 31, 2012		448,412
Subordinated Unitholders Equity at Dec. 31, 2012	$ 949,482			$ 949,482

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Long-Term Debt (Details) (USD $)	12 Months Ended						12 Months Ended		1 Months Ended				1 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Senior Notes [Member] Rate	Dec. 31, 2010 Senior Notes [Member]	Nov. 30, 2006 Senior Notes [Member]	Dec. 31, 2012 Senior Notes [Member] 2013 Senior Notes [Member]	Nov. 30, 2006 Senior Notes [Member] 2013 Senior Notes [Member]	Sep. 30, 2008 Senior Notes [Member] 2016 Notes [Member]	Dec. 31, 2012 Senior Notes [Member] 2016 Notes [Member]	Nov. 30, 2006 Senior Notes [Member] 2016 Notes [Member]	Oct. 31, 2012 Senior Notes [Member] 2020 Notes [Member]	Jul. 31, 2012 Revolving Credit Facility [Member] Liquefaction Credit Facility [Member]	Jul. 31, 2012 Revolving Credit Facility [Member] Liquifaction Credit Facility - LIBOR Loans [Member]	Jul. 31, 2012 Construction [Member] Liquifaction Credit Facility - LIBOR Loans [Member]	Jul. 31, 2012 Construction [Member] Liquifaction Credit Facility - Base Rate Loans [Member]	Jul. 31, 2012 Operations [Member] Liquifaction Credit Facility - LIBOR Loans [Member]	Jul. 31, 2012 Operations [Member] Liquifaction Credit Facility - Base Rate Loans [Member]
Debt Instrument [Line Items]
Debt instrument principal amount						$ 2,032,000,000		$ 550,000,000			$ 1,482,000,000	$ 420,000,000	$ 3,600,000,000
Debt instrument stated rate (percent)								7.25%			7.50%	6.50%
Gains (Losses) on Extinguishment of Debt	(42,587,000)	0	0				(42,587,000)
Debt Instrument, Increase, Additional Borrowings									183,500,000
Redemption of Debt Instrument, Percentage										100.00%
Percentage of debt principal										1.00%
Debt instrument fixed charge coverage ratio				2
Distribution made during the period	333,453,000	313,619,000			374,800,000
Additional borrowings under the Liquefaction Credit Facility													100,000,000
Debt instrument variable rate basis													LIBOR
Debt instrument basis spread															3.50%	2.50%	3.75%	2.75%
Upfront fee required under Liquefaction Credit Facility													178,000,000
Commitment fee as a percentage of LIBOR loans (percent)														40.00%
Amortization period of scheduled repayments													18 years
Restricted cash collateral	100,000,000
Miinimum percentage of projected outstanding borrowings required to be hedged													75.00%
Maximum forecasted borrowings under the Liquefaction Credit Facility													$ 2,900,000,000
Interest rate on the forecasted borrowings under the Liquefaction Credit Facility													1.98%

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Supplemental Cash Flow Information and Disclosures of Non-cash Transactions (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Cash Flow Elements [Abstract]

Schedule of Supplemental Cash Flow Disclosures

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

	Year Ended December 31,
	2012		2011		2010
Cash paid during the year for interest, net of amounts capitalized	$	160,273	$	164,513	$	164,793
LNG terminal costs funded with accounts payable and accrued liabilities	99,680		—		—

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Supplmental Cash Flow Information and Disclosures of Non-Cash Transactions (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest, net of amounts capitalized	$ 160,273	$ 164,513	$ 164,793
Construction-in-process funded with accrued liabilities	$ 99,680	$ 0	$ 0

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

COMMITMENTS AND CONTINGENCIES [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

LNG Commitments

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.

Bechtel EPC Contract

Sabine Pass Liquefaction has entered into lump sum turnkey contracts for the engineering, procurement and construction of Train 1 and Train 2 (the "EPC Contract (Train 1 and 2)") and Train 3 and Train 4 (the "EPC Contract (Train 3 and 4)", and together with the EPC Contract (Train 1 and 2), the "EPC Contracts"), with Bechtel in November 2011 and December 2012, respectively.

The EPC Contract (Train 1 and 2) 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 up to $30.0 million depending on the termination date.

The EPC Contract (Train 3 and 4) with Bechtel provides for (i) the procurement, engineering, design, installation, training, commissioning and placing into service of Train 3 and Train 4 and related facilities and (ii) certain modifications and improvements to Train 1, Train 2 and the Sabine Pass LNG terminal. The EPC Contract (Train 3 and 4) provides that Sabine Pass Liquefaction will pay Bechtel a contract price of $3.8 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. If Sabine Pass Liquefaction fails to issue the notice to proceed by December 31, 2013, 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.

Services Agreements

We have entered into certain services agreements with affiliates. See Note 13—"Related Party Transactions" for information regarding such agreements.

Public Company Expenses

We and Sabine Pass LNG are reporting entities under the Exchange Act. As a result, our combined total annual general and administrative expenses will include costs related to compliance with the Sarbanes-Oxley Act of 2002, filing annual and quarterly reports with the SEC, increased audit fees, tax compliance and publicly traded partnership tax reporting, investor relations, director compensation, directors’ and officers’ insurance, legal fees, registrar and transfer agent fees and stock exchange fees. Cheniere advanced us funds to pay public company expenses associated with being a publicly traded partnership through 2008, after which time we used available cash to pay such expenses directly and, after payment of the initial quarterly distribution on all units, to reimburse Cheniere.

Crest Royalty

Under a settlement agreement with Crest Energy dated as of June 14, 2001, Cheniere 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 was calculated based on the volume of natural gas processed through covered LNG facilities, subject to a minimum of $2.0 million and a maximum of approximately $11.0 million per production year. In 2003, Freeport LNG contractually assumed the obligation to pay the Crest Royalty for natural gas processed at Freeport LNG's receiving terminal. Subsequently, the calculation of the Crest Royalty and the scope of Freeport LNG's assumed obligation to pay the Crest Royalty became the subject of litigation involving Cheniere, Crest Energy, and Freeport LNG ("Crest Royalty Litigation").

In March 2012, Cheniere purchased all of the rights, title, and interest in the Crest Royalty from Crest Energy. That purchase resulted in Crest Energy's dismissal from the Crest Royalty Litigation. In September 2012, Cheniere entered into a settlement of the remaining claims in the Crest Royalty Litigation with Freeport LNG. As part of the settlement agreement, Cheniere terminated the Crest Royalty. As a result of all of these transactions, Cheniere resolved disputes persisting since 2001 related to real property at Freeport LNG and has released us from the first priority lien that had been granted to holders of the Crest Royalty.

Restricted Net Assets

At December 31, 2012, our restricted net assets of consolidated subsidiaries were approximately $972.4 million.

Other Commitments

State Tax Sharing Agreement

In November 2006, Sabine Pass LNG and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass LNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass LNG will pay to Cheniere an amount equal to the state and local tax that Sabine Pass LNG would be required to pay if Sabine Pass LNG's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass LNG under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass LNG. The agreement is effective for tax returns due on or after January 1, 2008.

In August 2012, Sabine Pass Liquefaction and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass Liquefaction and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass Liquefaction will pay to Cheniere an amount equal to the state and local tax that Sabine Pass Liquefaction would be required to pay if Sabine Pass Liquefaction's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass Liquefaction under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass Liquefaction. The agreement is effective for tax returns due on or after August 2012.

Cooperative Endeavor Agreements ("CEAs")

In July 2007, Sabine Pass LNG executed CEAs with various Cameron Parish, Louisiana taxing authorities. See Note 13—"Related Party Transactions" for information regarding such agreements.

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, 2012, 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.

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Cash Distribution and Net Income (Loss) per Common Unit (Tables)

12 Months Ended

Dec. 31, 2012

Earnings Per Share [Abstract]

Schedule of Distributions Made to Members or Limited Partners, by Distribution

The following provides a summary of distributions paid by us during the years ended December 31, 2012, 2011 and 2010:

						Total Distribution (in thousands)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Distribution Per Subordinated Unit		Common Units		Class B Units	Subordinated Units	General Partner Units
November 14, 2012	July 1 - September 30, 2012	$	0.425	$	—	$	16,783	—	—	$	342
August 13, 2012	April 1 - June 30, 2012	0.425		—		13,383		—	—	273
May 14, 2012	January 1 - March 31, 2012	0.425				13,323		—		272
February 12, 2012	October 1 - December 31, 2011	0.425				13,176		—		269
November 14, 2011	July 1 - September 30, 2011	0.425		—		13,176		—	—	269
August 12, 2011	April 1 - June 30, 2011	0.425		—		11,446		—	—	234
May 13, 2011	January 1 - March 31, 2011	0.425		—		11,335		—	—	231
February 11, 2011	October 1 - December 31, 2010	0.425		—		11,229		—	—	229
November 12, 2010	July 1 - September 30, 2010	0.425		—		11,227		—	—	229
August 13, 2010	April 1 - June 30, 2010	0.425		—		11,227		—	—	229
May 14, 2010	January 1 - March 31, 2010	0.425		0.425		11,227		—	57,538	1,403
February 12, 2010	October 1 - December 31, 2009	0.425		0.425		11,227		—	57,538	1,403

Schedule of Weighted Average Number of Shares

The following table provides a reconciliation of net income (loss) and the allocation of net income (loss) to the common units and the subordinated units for purposes of computing net income (loss) per unit (in thousands, except per unit data):

				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner
Year Ended December 31, 2012
Net loss	$	(150,136	)
Declared distributions	61,501			60,271			—		—			1,230
Amortization of beneficial conversion feature of Class B units	—			(5,149		)	25,319		(20,170		)	—
Assumed allocation of undistributed net loss	(211,637		)	(46,061		)	—		(157,917		)	(7,659		)
Assumed allocation of net income (loss)				$	9,061		$	25,319	$	(178,087	)	$	(6,429	)
Weighted average units outstanding				33,470			43,303		135,384
Net income (loss) per unit				$	0.27		$	0.58	$	(1.32	)
Year Ended December 31, 2011
Net loss	$	(31,019	)
Declared distributions	50,136			49,134			—		—			1,002
Assumed allocation of undistributed net loss	(81,155		)	(14,819		)	—		(64,713		)	(1,623		)
Assumed allocation of net income (loss)				$	34,315		$	—	$	(64,713	)	$	(621	)
Weighted average units outstanding				27,910			—		135,384
Net income (loss) per unit				$	1.23		$	—	$	(0.48	)
Year Ended December 31, 2010
Net income	$	107,568
Declared distributions	104,538			44,910			—		57,538			2,090
Assumed allocation of undistributed net loss	3,030			—			—		2,969			61
Assumed allocation of net income				$	44,910		$	—	$	60,507		$	2,151
Weighted average units outstanding				26,416			—		135,384
Net income per unit				$	1.70		$	—	$	0.45

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Cash Distributions and Net Income (Loss) per Common Unit

12 Months Ended

Dec. 31, 2012

CASH DISTRIBUTIONS AND NET INCOME (LOSS) PER COMMON UNIT [Abstract]

Cash Distributions and Net Income (Loss) per Common Unit

Cash Distributions and Net Income (Loss) per Common Unit

Cash Distributions

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Generally, our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from operating surplus as defined in the partnership agreement. The following provides a summary of distributions paid by us during the years ended December 31, 2012, 2011 and 2010:

						Total Distribution (in thousands)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Distribution Per Subordinated Unit		Common Units		Class B Units	Subordinated Units	General Partner Units
November 14, 2012	July 1 - September 30, 2012	$	0.425	$	—	$	16,783	—	—	$	342
August 13, 2012	April 1 - June 30, 2012	0.425		—		13,383		—	—	273
May 14, 2012	January 1 - March 31, 2012	0.425				13,323		—		272
February 12, 2012	October 1 - December 31, 2011	0.425				13,176		—		269
November 14, 2011	July 1 - September 30, 2011	0.425		—		13,176		—	—	269
August 12, 2011	April 1 - June 30, 2011	0.425		—		11,446		—	—	234
May 13, 2011	January 1 - March 31, 2011	0.425		—		11,335		—	—	231
February 11, 2011	October 1 - December 31, 2010	0.425		—		11,229		—	—	229
November 12, 2010	July 1 - September 30, 2010	0.425		—		11,227		—	—	229
August 13, 2010	April 1 - June 30, 2010	0.425		—		11,227		—	—	229
May 14, 2010	January 1 - March 31, 2010	0.425		0.425		11,227		—	57,538	1,403
February 12, 2010	October 1 - December 31, 2009	0.425		0.425		11,227		—	57,538	1,403

The subordinated units will receive distributions only to the extent we have available cash above the minimum quarterly distribution requirement for our common unitholders and general partner and certain reserves.  As a result of the assignment of Cheniere Marketing's TUA to Cheniere Investments, effective July 1, 2010, our available cash for distributions was reduced. Therefore, we have not paid distributions on our subordinated units since the distribution made with respect to the quarter ended March 31, 2010.

Pursuant to the Blackstone and Cheniere Unit Purchase Agreements, we issued and sold 133.3 million Class B units at a price of $15.00 per Class B unit in the year ended ended December 31, 2012, resulting in total gross proceeds of $2.0 billion. The Class B units were issued at a discount to the market price of the common units into which they are convertible.  This discount totaling $1,950.0 million represents a beneficial conversion feature and is reflected as an increase in common and subordinated unitholders’ capital and a decrease in Class B unitholders’ capital to reflect the fair value of the Class B units at issuance on our consolidated statement of partners’ and owners' capital (deficit).  The beneficial conversion feature is considered a dividend that will be distributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders' capital and a decrease in common and subordinated unitholders’ capital.  The impact of the beneficial conversion feature is also included in earnings per unit for the year endedDecember 31, 2012.

Net Income (Loss) per Common Unit

Net income (loss) per common unit for a given period is based on the distributions that will be made to the unitholders with respect to the period plus an allocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. The two class method dictates that net income (loss) for a period be reduced by the amount of available cash that will be distributed with respect to that period and that any residual amount representing undistributed net income be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income as if all of the net income for the period had been distributed in accordance with the partnership agreement. Undistributed income is allocated to participating securities based on the distribution waterfall for available cash specified in the partnership agreement. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units and other participating securities on a pro rata basis based on provisions of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

Under our partnership agreement, the incentive distribution rights ("IDRs") participate in net income (loss) only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss). We did not allocate earnings or losses to IDR holders for the purpose of the two class method earnings per unit calculation for any of the periods presented.

The following table provides a reconciliation of net income (loss) and the allocation of net income (loss) to the common units and the subordinated units for purposes of computing net income (loss) per unit (in thousands, except per unit data):

				Limited Partner Units
	Total			Common Units			Class B Units		Subordinated Units			General Partner
Year Ended December 31, 2012
Net loss	$	(150,136	)
Declared distributions	61,501			60,271			—		—			1,230
Amortization of beneficial conversion feature of Class B units	—			(5,149		)	25,319		(20,170		)	—
Assumed allocation of undistributed net loss	(211,637		)	(46,061		)	—		(157,917		)	(7,659		)
Assumed allocation of net income (loss)				$	9,061		$	25,319	$	(178,087	)	$	(6,429	)
Weighted average units outstanding				33,470			43,303		135,384
Net income (loss) per unit				$	0.27		$	0.58	$	(1.32	)
Year Ended December 31, 2011
Net loss	$	(31,019	)
Declared distributions	50,136			49,134			—		—			1,002
Assumed allocation of undistributed net loss	(81,155		)	(14,819		)	—		(64,713		)	(1,623		)
Assumed allocation of net income (loss)				$	34,315		$	—	$	(64,713	)	$	(621	)
Weighted average units outstanding				27,910			—		135,384
Net income (loss) per unit				$	1.23		$	—	$	(0.48	)
Year Ended December 31, 2010
Net income	$	107,568
Declared distributions	104,538			44,910			—		57,538			2,090
Assumed allocation of undistributed net loss	3,030			—			—		2,969			61
Assumed allocation of net income				$	44,910		$	—	$	60,507		$	2,151
Weighted average units outstanding				26,416			—		135,384
Net income per unit				$	1.70		$	—	$	0.45

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Subsequent Events (Details) (Senior Notes [Member], USD $) In Millions, unless otherwise specified	Nov. 30, 2006	Feb. 28, 2013 Senior Secured Notes Due 2021 [Member] Issuance of Debt [Member]
Subsequent Event [Line Items]
Debt instrument principal amount	$ 2,032.0	$ 1,500.0
Debt instrument stated rate (percent)		5.625%

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Consolidated Statements of Cash Flows (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash flows from operating activities
Net income (loss)	$ (150,136,000)	$ (31,019,000)	$ 107,568,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	42,551,000	42,943,000	42,299,000
Use of restricted cash and cash equivalents	75,060,000	0	0
Non-cash LNG inventory—affiliate write-downs	0	10,600,000	0
Amortization of debt discount	4,695,000	4,695,000	4,695,000
Amortization of debt issuance costs	4,362,000	4,382,000	4,863,000
Non-cash derivative loss	(619,000)	(195,000)	124,000
Loss on early extinguishment of debt	(1,470,000)	0	0
Other	3,496,000	0	0
Changes in operating assets and liabilities:
Accounts and interest receivable	481,000	853,000	(626,000)
Accounts receivable—affiliate	(1,677,000)	384,000	2,874,000
Accounts payable and accrued liabilities	1,960,000	(1,173,000)	3,035,000
Accounts payable and accrued liabilities—affiliate	2,412,000	(1,640,000)	2,566,000
Deferred revenue—affiliate	8,000	15,000	(62,833,000)
Deferred revenue	(4,089,000)	(3,964,000)	(3,864,000)
Advances to affiliate	(4,764,000)	2,851,000	1,815,000
LNG inventory—affiliate	(51,000)	(14,969,000)	0
Other	(1,373,000)	486,000	1,621,000
Net cash provided by operating activities	(26,214,000)	14,249,000	104,137,000
Cash flows from investing activities
Use of restricted cash and cash equivalents	1,114,742,000	0	0
LNG terminal construction-in-process	(1,118,457,000)	(7,137,000)	(4,955,000)
Advances under long-term contracts	(740,000)	(1,054,000)	(121,000)
Net cash used in investing activities	(4,455,000)	(8,191,000)	(5,076,000)
Cash flows from financing activities
Proceeds from sale of Class B units, net	1,887,342,000	0	0
Proceeds from 2020 Notes	420,000,000	0	0
Proceeds from Liquefaction Credit Facility	100,000,000	0	0
Proceeds from sale of partnership units	250,022,000	70,157,000	0
Distributions to unitholders	(57,821,000)	(48,149,000)	(163,249,000)
Proceeds from sale of partnership units	11,100,000	9,000,000
Use of (investment in) restricted cash and cash equivalents	(1,458,619,000)	0	0
Repayment of 2013 Notes	(550,000,000)	0	0
Debt issuance costs	(222,378,000)	0	0
Other	0	0	(5,000)
Net cash used in financing activities	368,546,000	22,008,000	(163,254,000)
Net increase (decrease) in cash and cash equivalents	337,877,000	28,066,000	(64,193,000)
Cash and cash equivalents—beginning of period	81,415,000	53,349,000	117,542,000
Cash and cash equivalents—end of period	$ 419,292,000	$ 81,415,000	$ 53,349,000

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Consolidated Balance Sheet Parentheticals	Dec. 31, 2012	Dec. 31, 2011
General partner ownership interest percentage	2.00%	2.00%
General partner, units Issued	6,289,911	3,395,653
General partner, units outstanding	6,289,911	3,395,653
Common Units
Partnership untiholders, units issued	39,488,488	31,003,154
Partnership untiholders, units outstanding	39,488,488	31,003,154
Class B Unit [Member]
Partnership untiholders, units issued	133,333,334	0
Partnership untiholders, units outstanding	133,333,334	0
Subordinated Units
Partnership untiholders, units issued	135,383,831	135,383,831
Partnership untiholders, units outstanding	135,383,831	135,383,831

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Deferred Revenue

12 Months Ended

Dec. 31, 2011

Deferred Revenue [Abstract]

Deferred Revenue

DEFERRED REVENUE

Advance Capacity Reservation Fee

In November 2004, Total Gas & 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.

As of December 31, 2012, we had recorded $4.0 million and $21.5 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, 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.

TUA Payments

Following the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008, Sabine Pass LNG began receiving capacity reservation fee payments from Cheniere Marketing under its TUA. Effective July 1, 2010, Cheniere Marketing assigned its existing TUA with Sabine Pass LNG to Cheniere Investments, including all of its rights, titles, interests, obligations and liabilities in and under the TUA. After the assignment of the TUA from Cheniere Marketing to Cheniere Investments, Cheniere Investments began making its TUA payments on a monthly basis. Sabine Pass Liquefaction obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, Sabine Pass LNG, Sabine Pass Liquefaction and Cheniere Investments entered into a terminal use rights assignment and agreement ("TURA") pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to Sabine Pass LNG. We have guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA. However, the revenue earned by Sabine Pass LNG from Cheniere Investments' capacity payments under its TUA was eliminated and under its TURA is eliminated upon consolidation of our financial statements. As a result, we have zero current deferred revenue—affiliate related to Cheniere Investments' monthly advance capacity reservation fee payment as of December 31, 2012 and 2011.

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, 2012 and 2011, we had recorded $21.1 million as current deferred revenue on our Consolidated Balance Sheets related to Total's and Chevron's monthly TUA payments.

Cooperative Endeavor Agreements

In July 2007, Sabine Pass LNG executed Cooperative Endeavor Agreements ("CEAs") with various Cameron Parish, Louisiana taxing authorities that allow them to accelerate certain of its property tax payments scheduled to begin in 2019. This ten-year initiative represents an aggregate $25.0 million commitment, and will make resources available to the Cameron Parish taxing authorities on an accelerated basis in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for Sabine Pass LNG’s advance payments of ad valorem taxes, Cameron Parish will grant Sabine Pass LNG a dollar for dollar credit against future ad valorem taxes to be levied against its LNG terminal starting in 2019. In September 2007, Sabine Pass LNG entered into an agreement with Cheniere Marketing, pursuant to which Cheniere Marketing will advance it any and all amounts payable under the CEAs in exchange for a similar amount of credits against future ad valorem reimbursements it would owe to Sabine Pass LNG under its TUA starting in 2019. These advance ad valorem tax payments were recorded to other assets, and payments from Cheniere Marketing that Sabine Pass LNG utilized to make the early payment of taxes were recorded as deferred revenue. As of December 31, 2012 and 2011, we had $14.7 million and $12.3 million, respectively, of other non-current assets and non-current deferred revenue resulting from accelerated ad valorem tax payments.

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Document and Entity Information (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Feb. 13, 2013	Jun. 30, 2012
Entity Information [Line Items]
Entity Registrant Name	Cheniere Energy Partners, L.P.
Entity Central Index Key	0001383650
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		39,488,488
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 439

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Long-Term Debt

12 Months Ended

Dec. 31, 2012

Long-term Debt, Unclassified [Abstract]

Long-term Debt

LONG-TERM DEBT

As of December 31, 2012 and 2011, our long-term debt consisted of the following (in thousands):

	December 31,
	2012			2011
Long-term debt
2013 Notes	$	—		$	550,000
2016 Notes	1,665,500			1,665,500
2020 Notes	420,000			—
Liquefaction Credit Facility	100,000			—
Total long-term, debt	2,185,500			2,215,500
Long-term debt discount
2016 Notes	(18,387		)	(23,082		)
Total long-term debt, net of discount	$	2,167,113		$	2,192,418

Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2012 (in thousands): 

	Payments Due for the Years Ended December 31,
	Total		2013		2014 to 2015		2016 to 2017		Thereafter
Debt (including related parties):
2016 Notes	$	1,665,500	$	—	$	—	$	1,665,500	$	—
2020 Notes	420,000		—		—		—		420,000
Liquefaction Credit Facility	100,000		—		—		—		100,000
Debt (including related parties)	$	2,185,500	$	—	$	—	$	1,665,500	$	520,000

Senior Notes

In November 2006, Sabine Pass LNG issued an aggregate principal amount of $2,032.0 million of Senior Secured Notes, consisting of $550.0 million of 7.25% Senior Secured Notes due 2013 (the "2013 Notes") and $1,482.0 million of 7.50% Senior Secured Notes due 2016 (the "2016 Notes"). 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. In October 2012, Sabine Pass LNG issued an aggregate principal amount of $420.0 million of 6.50% Senior Secured Notes due in 2020 (the "2020 Notes"), whose terms were substantially similar to the outstanding 2016 Notes, and redeemed all of the 2013 Notes. As a result, we recorded a $42.6 million loss on early extinguishment of debt primarily related to make-whole payments. Collectively, the 2013 Notes, 2016 Notes, and 2020 Notes are referred to as the "Senior Notes." Interest on the 2016 Notes is payable semi-annually in arrears on May 30 and November 30 of each year. Interest on the 2020 Notes is payable semi-annually in arrears on May 1 and November 1 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 its 2016 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 2016 Notes; or

• the excess of: a) the present value at such redemption date of (i) the redemption price of the 2016 Notes plus (ii) all required interest payments due on the 2016 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 2016 Notes, if greater.

Sabine Pass LNG may redeem all or part of its 2020 Notes at any time on or after November 1, 2016, at fixed redemption prices specified in the Indenture, plus accrued and unpaid interest, if any, to the date of redemption. Sabine Pass LNG may also, at its option, redeem all or part of the 2020 Notes at any time prior to November 1, 2016, at a "make-whole" price set forth in the Indenture, plus accrued and unpaid interest, if any, to the date of redemption.

Under the indentures governing the Senior Notes, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. 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 indenture. During the years ended December 31, 2012, 2011 and 2010, Sabine Pass LNG made distributions of $333.5 million, $313.6 million and $374.8 million, respectively, after satisfying all the applicable conditions in the indenture.

In connection with the issuance of the 2020 Notes, Sabine Pass LNG also entered into a registration rights agreement (the "Registration Rights Agreement"). Under the Registration Rights Agreement, Sabine Pass LNG has agreed to use reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to exchange the notes for an issue of SEC-registered notes with terms substantially identical to the 2020 Notes within 360 days after the 2020 Notes were issued. In certain circumstances, Sabine Pass LNG may be required to file a shelf registration statement to cover resales of the 2020 Notes. If Sabine Pass LNG fails to satisfy these obligations, Sabine Pass LNG may be required to pay additional interest to holders of the 2020 Notes under certain circumstances.

Liquefaction Credit Facility

In July 2012, Sabine Pass Liquefaction entered into the $3.6 billion Liquefaction Credit Facility with a syndicate of lenders. The Liquefaction Credit Facility will be used to fund a portion of the costs of developing, constructing and placing into operation Train 1 and Train 2 of the Liquefaction Project. The Liquefaction Credit Facility will mature on the earlier of July 31, 2019 or the second anniversary of the completion date of Train 1 and Train 2 of the Liquefaction Project, as defined in the Liquefaction Credit Facility. Borrowings under the Liquefaction Credit Facility may be refinanced, in whole or in part, at any time without premium or penalty, except for interest hedging and interest rate breakage costs. Sabine Pass Liquefaction made a $100.0 million borrowing under the Liquefaction Credit Facility in August 2012 after meeting the required conditions precedent to the initial advance.

Borrowings under the Liquefaction Credit Facility bear interest, at Sabine Pass Liquefaction's election, at a variable rate equal to LIBOR or the base rate, plus the applicable margin. The applicable margin for LIBOR loans is 3.50% during construction and 3.75% during operations, and the applicable margin for base rate loans is 2.50% during construction and 2.75% during operations. Interest on LIBOR loans is due and payable at the end of each LIBOR period, and interest on base rate loans is due and payable at the end of each calendar quarter. The Liquefaction Credit Facility required Sabine Pass Liquefaction to pay certain up-front fees to the agents and lenders in the aggregate amount of approximately $178 million and provides for a commitment fee calculated at a rate per annum equal to 40% of the applicable margin for LIBOR loans, multiplied by the average daily amount of the undrawn commitment. Annual administrative fees must also be paid to the agent and the trustee. The principal of loans made under the Liquefaction Credit Facility must be repaid in quarterly installments, commencing with the first calendar quarter ending at least three months following the completion of Train 1 and Train 2 of the Liquefaction Project. Scheduled repayments are based upon an 18-year amortization, with the remaining balance due upon the maturity of the Liquefaction Credit Facility.

Under the terms and conditions of the Liquefaction Credit Facility, all cash held by Sabine Pass Liquefaction is controlled by the collateral agent. These funds can only be released by the collateral agent upon satisfaction of certain terms and conditions, including receipt of satisfactory documentation that the Liquefaction Project costs are bona fide expenditures and are permitted under the terms of the Liquefaction Credit Facility. The Liquefaction Credit Facility does not permit Sabine Pass Liquefaction to hold any cash, or cash equivalents, outside of the accounts established under the agreement. Because these cash accounts are controlled by the collateral agent, the cash balance of $100.0 million held in these accounts as of December 31, 2012 is classified as restricted on our Consolidated Balance Sheets.

The Liquefaction Credit Facility contains customary conditions precedent for the second borrowing and any subsequent borrowings, as well as customary affirmative and negative covenants. The obligations of Sabine Pass Liquefaction under the Liquefaction Credit Facility are secured by substantially all of the assets of Sabine Pass Liquefaction as well as all of the membership interests in Sabine Pass Liquefaction, and a security interest in Cheniere Partners' rights under the Blackstone Unit Purchase Agreement and the guaranty related thereto.

Under the terms of the Liquefaction Credit Facility, Sabine Pass Liquefaction is required to hedge against the potential of rising interest rates with respect to no less than 75% (calculated on a weighted average basis) of the projected outstanding borrowings. In connection with the closing of the Liquefaction Credit Facility, Sabine Pass Liquefaction entered into interest rate swap agreements. The swap agreements have the effect of fixing the LIBOR component of the interest rate payable under the Liquefaction Credit Facility with respect to forecasted borrowings under the Liquefaction Credit Facility up to a maximum of $2.9 billion at 1.98% from August 14, 2012 to July 31, 2019, the final termination date of the swap agreements.

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Consolidated Statements of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues
Revenues	$ 256,354	$ 269,183	$ 268,328
Revenues—affiliate	7,973	14,607	130,954
Total revenues	264,327	283,790	399,282
Expenses
Operating and maintenance expense	35,457	21,827	27,069
Operating Costs and Expenses Related Parties	16,300	11,918	12,090
Depreciation expense	42,551	42,943	42,299
Development expense	37,559	32,448	8,738
Research and Development Expense Related Parties	2,677	4,025	1,824
General and administrative expense	10,303	5,534	6,190
General and Administrative Expense Related Parties	55,940	20,469	20,275
Total expenses	200,787	139,164	118,485
Income from operations	63,540	144,626	280,797
Other income (expense)
Interest expense, net	(171,646)	(173,590)	(174,016)
Gains (Losses) on Extinguishment of Debt	(42,587)	0	0
Derivative gain (loss), net	58	(2,251)	461
Other	499	196	326
Total other expense	(213,676)	(175,645)	(173,229)
Net income (loss)	$ (150,136)	$ (31,019)	$ 107,568
Net income (loss) per common unit - basic and diluted		$ 1.23	$ 1.70
Weighted average units outstanding		27,910	26,416

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LNG inventory and LNG Inventory - Affiliate

12 Months Ended

Dec. 31, 2012

LNG Inventory And LNG Inventory - Affiliate [Abstract]

LNG Inventory and LNG Inventory - Affiliate

LNG INVENTORY AND LNG INVENTORY—AFFILIATE

LNG inventory and LNG inventory—affiliate are recorded at cost and are subject to lower of cost or market ("LCM") adjustments at the end of each period. LNG inventory—affiliate represents LNG inventory purchased under a related party LNG lease agreement with Cheniere Marketing, LLC ("Cheniere Marketing"), a wholly owned subsidiary of Cheniere, as described in Note 13—"Related Party Transactions". 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, 2012 and 2011, we had $2.6 million and $0.5 million, respectively, of LNG inventory on our Consolidated Balance Sheets. During the years ended December 31, 2012, 2011 and 2010, we recognized $9.4 million, $0.4 million and $0.3 million, respectively, as a result of LCM adjustments to our LNG inventory.

As of December 31, 2012 and 2011, we had $4.4 million of LNG inventory—affiliate on our Consolidated Balance Sheets. During the years ended December 31, 2012 and 2011 and 2010, we recognized $11.0 million,$10.6 million and zero, respectively, as a result of LCM adjustments to our LNG inventory—affiliate.

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Restricted Cash and Cash Equivalents

12 Months Ended

Dec. 31, 2012

Cash and Cash Equivalents [Abstract]

Restricted Cash and Cash Equivalents [Text Block]

RESTRICTED CASH AND CASH EQUIVALENTS

Restricted cash and cash equivalents consists 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 2013 Notes and 2016 Notes and $420.0 million of 2020 Notes (See Note 11—"Long-Term Debt"). Collectively, the 2013 Notes, 2016 Notes, and 2020 Notes are referred to as the "Senior Notes." Under the indentures governing the Senior Notes (the "Sabine Pass Indentures"), 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. 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 Indentures.

As of December 31, 2012 and 2011, we classified $17.4 million and $13.7 million, respectively, as current restricted cash and cash equivalents for the payment of interest due within twelve months. As of December 31, 2012 and 2011, we classified the permanent debt service reserve fund of $76.1 million and $82.4 million, respectively, 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.

Liquefaction Reserve

In July 2012, Sabine Pass Liquefaction closed on a $3.6 billion senior secured credit facility (the "Liquefaction Credit Facility"). Under the terms and conditions of the Liquefaction Credit Facility, Sabine Pass Liquefaction is required to deposit all cash received into reserve accounts controlled by a collateral trustee. Therefore, all of Sabine Pass Liquefaction's cash and cash equivalents are shown as restricted cash and cash equivalents on our Consolidated Balance Sheets. As of December 31, 2012, we classified $100.0 million as non-current restricted cash and cash equivalents held by Sabine Pass Liquefaction as such funds are to be used to acquire non-current assets. As of December 31, 2012, we classified $75.1 million as current restricted cash and cash equivalents held by Sabine Pass Liquefaction as such funds are to be used to pay for current liabilities. As of December 31, 2012, we classified $96.3 million as non-current restricted cash and cash equivalents held by Sabine Pass Liquefaction as such funds are to be used to pay for the Liquefaction Project.

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Supplemental Cash Flow Information and Disclosures of Non-Cash Transactions

12 Months Ended

Dec. 31, 2012

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information and Disclosures of Non-cash Transactions

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,
	2012		2011		2010
Cash paid during the year for interest, net of amounts capitalized	$	160,273	$	164,513	$	164,793
LNG terminal costs funded with accounts payable and accrued liabilities	99,680		—		—

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Description of Equity Interests

12 Months Ended

Dec. 31, 2011

Description of Equity Interests [Abstract]

Description of Equity Interests

DESCRIPTION OF EQUITY INTERESTS

The common units, Class B units and subordinated units represent limited partner interests in us. The holders of the units are entitled to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. On May 31, 2007, Cheniere LNG Holdings, LLC contributed all of its 135,383,831 subordinated units to Cheniere Subsidiary Holdings, LLC.

The common units have the right to receive minimum quarterly distributions of $0.425, plus any arrearages thereon, before any distribution is made to the holders of the subordinated units. Subordinated units will convert into common units on a one-for-one basis when we meet financial tests specified in the partnership agreement. Although common and subordinated unitholders are not obligated to fund losses of the partnership, their capital accounts, which would be considered in allocating the net assets of the partnership were it to be liquidated, continue to share in losses.

The general partner interest is entitled to at least 2% of all distributions made by us. In addition, the general partner holds incentive distribution rights, which allow the general partner to receive a higher percentage of quarterly distributions of available cash from operating surplus after the minimum distributions have been achieved and as additional target levels are met. The higher percentages range from 15% up to 50%.

In January 2011, we 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 the Liquefaction Project. During the year ended December 31, 2011, we sold 0.5 million common units with net proceeds of $9.0 million. During the year endedDecember 31, 2012, we sold 0.5 million common units in connection with the at-the-market program with net proceeds of $11.1 million. We paid $0.3 million in commissions to Miller Tabak + Co., Inc., as sales agent, in connection with the at-the-market program during the year endedDecember 31, 2012.

In September 2011, we 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. We received net proceeds of approximately $60 million that we are using for general business purposes, including development costs associated with the Liquefaction Project. In September 2012, we sold 8.0 million common units in an underwritten public offering at a price of $25.07 per common unit. We received net proceeds of $194.0 million that were used for partial repayment of Sabine Pass LNG's 2013 Notes, and, to the extent not so used, for general business purposes.

During the year ended December 31, 2011, we also received $1.5 million in net proceeds from our general partner in connection with the exercise of its right to maintain its 2% ownership interest in us. We received $45.1 million in net proceeds from our general partner in connection with the exercise of its right to maintain its 2% ownership interest in us during the year endedDecember 31, 2012.

In May 2012, we and Blackstone CQP Holdco LP ("Blackstone") entered into a unit purchase agreement (the "Blackstone Unit Purchase Agreement") .  Under the Blackstone Purchase Unit Agreement, Blackstone agreed to purchase $1.5 billion of newly issued Cheniere Partners Class B units ("Class B units") from us in a private placement.  In May 2012, Cheniere also entered into a unit purchase agreement with us (the "Cheniere Unit Purchase Agreeement"). Under the Cheniere Unit Purchase Agreement, Cheniere agreed to purchase $500.0 million of newly issued Class B units. During the year endedDecember 31, 2012, Blackstone and Cheniere completed their acquisitions of 100.0 million and 33.3 million Class B units, respectively, under their unit purchase agreements for total consideration of $1.5 billion and $500.0 million, respectively. Proceeds from the financings are being used to fund the equity portion of the costs of developing, constructing and placing into service the Liquefaction Project. 

The Class B units are subject to conversion, mandatorily or at the option of the holders of the Class B units under specified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basis beginning on the initial purchase of the Class B units, and ending on the conversion date of the Class B units, the conversion value of the Class B units increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. The Class B units are not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale of substantially all of our assets). The holders of Class B units have a preference over the holders of the subordinated units in the event of a liquidation (or merger, combination or sale of substantially all of our assets). The Class B units will mandatorily convert into common units upon the earlier of the substantial completion date of Train 3 or August 9. 2017, provided that if Train 3 notice to proceed with construction is issued prior to August 9. 2017, then the mandatory conversion date becomes the substantial completion date of Train 3.

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Financial Instruments

12 Months Ended

Dec. 31, 2012

Financial Instruments [Abstract]

Financial Instruments

FINANCIAL INSTRUMENTS

Derivative Instruments

We have entered into certain instruments to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory ("LNG Inventory Derivatives"), to hedge the exposure to 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 volatility in a portion of the floating-rate interest payments under the Liquefaction Credit Facility ("Interest Rate Derivatives").

The following table (in thousands) shows the fair value of our derivative assets and liabilities that are required to be measured at fair value on a recurring basis as of December 31, 2012 and 2011, which are classified as other current assets, other current liabilities and other non-current liabilities in our Consolidated Balance Sheets.

	Fair Value Measurements as of
	December 31, 2012								December 31, 2011
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
LNG Inventory Derivatives asset	$	—	$	232	$	—	$	232	$	—	$	1,610	$	—	$	1,610
Fuel Derivatives liability	—		98		—		98		—		1,415		—		1,415
Interest Rate Derivatives liability	—		26,424		—		26,424		—		—		—		—

The estimated fair values of our LNG Inventory Derivatives and Fuel Derivatives are the amount at which the instruments could be exchanged currently between willing parties. We value these derivatives using observable commodity price curves and other relevant data. We value our Interest Rate Derivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to the valuation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.

Commodity Derivatives

Changes in the fair value of our LNG Inventory Derivatives and Fuel Derivatives 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 following table (in thousands) shows the fair value and location of our LNG Inventory Derivatives and Fuel Derivatives on our Consolidated Balance Sheets:

		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2012		December 31, 2011
LNG Inventory Derivatives asset	Prepaid expenses and other	$	232	$	1,610
Fuel Derivatives liability	Other current liabilities	98		1,415

The following table (in thousands) shows the changes in the fair value and settlements of our LNG Inventory Derivatives recorded in marketing and trading revenues (losses) on our Consolidated Statements of Operations during the years endedDecember 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
LNG Inventory Derivatives gain	$	1,036	$	2,300	$	—

The following table (in thousands) shows the changes in the fair value and settlements of our Fuel Derivatives recorded in derivative gain (loss) on our Consolidated Statements of Operations during the years endedDecember 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012			2011			2010
Fuel Derivatives gain (loss)	$	(622	)	$	(2,251	)	$	461

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions.  Collateral of $0.9 million and $0.8 million deposited for such contracts, which has not been reflected in the derivative fair value tables, is included in the other current assets balance as of December 31, 2012, and 2011, respectively.

Interest Rate Swaps Designated as Cash Flow Hedges

In August 2012, Sabine Pass Liquefaction entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion of the variable interest payments on the Liquefaction Credit Facility.

Sabine Pass Liquefaction has elected to designate these Interest Rate Derivatives as hedging instruments which is required in order to qualify for cash flow hedge accounting. As a result of this cash flow hedge designation, we recognize the Interest Rate Derivatives as an asset or liability at fair value, and reflect changes in fair value through other comprehensive income in our Consolidated Statements of Comprehensive Loss. Any hedge ineffectiveness associated with the Interest Rate Derivatives is recorded immediately as derivative gain (loss) in our Consolidated Statements of Operations. The realized gain (loss) on the Interest Rate Derivatives is recorded as an (increase) decrease in interest expense on our Consolidated Statements of Operations to the extent not capitalized as part of the Liquefaction Project. The effective portion of the gains or losses on our Interest Rate Derivatives recorded in other comprehensive income is reclassified to earnings as interest payments on the Liquefaction Credit Facility impact earnings. In addition, amounts recorded in other comprehensive income are also reclassified into earnings if it becomes probable that the hedged forecasted transaction will not occur.

The Interest Rate Derivatives hedge approximately 75% of the weighted average of the expected outstanding borrowings over the term of the Liquefaction Credit Facility. The aggregate notional amount each month follows our expected borrowing schedule under the Liquefaction Credit Facility with an expected maximum swap notional amount outstanding of $2.9 billion in 2017. Based on the continued development of our financing strategy for the Liquefaction Project, in particular the fixed-rate debt as described in Note 18—"Subsequent Events", during the fourth quarter of 2012 we determined it was no longer probable that a portion of the forecasted variable interest payments on the Liquefaction Credit Facility would occur in the time period originally specified. As a result, a portion of the Interest Rate Derivatives were no longer effective hedges and the hedge relationships for this portion were de-designated as of October 1, 2012. Fair value adjustments on this de-designated portion of the Interest Rate Derivatives subsequent to October 1, 2012 are recorded within the Consolidated Statements of Operations. We have continued to maintain the Interest Rate Derivatives (both designated and de-designated) in anticipation of our upcoming financing needs, particularly for the financing of the construction of Train 3 and Train 4 of the Liquefaction Project, and have concluded that the likelihood of occurrence of our variable interest payments has not changed to probable not to occur. As a result, amounts recorded in other comprehensive income related to our designated and de-designated Interest Rate Derivatives will continue to remain in other comprehensive income until interest payments on the Liquefaction Credit Facility impact earnings.

At December 31, 2012, Sabine Pass Liquefaction had the following Interest Rate Derivatives outstanding that converted $20.0 million of the Liquefaction Credit Facility from a variable to a fixed interest rate. Sabine Pass Liquefaction pays a fixed interest rate on the swap and in exchange receives a variable interest rate based on the one-month LIBOR.

	Initial Notional Amount	Maximum Notional Amount	Effective Date	Maturity Date	Weighted Average Fixed Interest Rate Paid	Variable Interest Rate Received
Interest Rate Derivatives - Designated	$16.1 million	$2.3 billion	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR
Interest Rate Derivatives - De-designated	$3.9 million	$575.3 million	August 14, 2012	July 31, 2019	1.98%	One-month LIBOR

Interest Rate Derivatives were reflected in our Consolidated Balance Sheets at fair value with the effective portion of the Interest Rate Derivatives' gain or loss recorded in other comprehensive income. Fair value adjustments subsequent to October 1, 2012 on the de-designated portion of the Interest Rate Derivatives were recorded within the Consolidated Statements of Operations. The following table (in thousands) shows the fair value of our interest rate swaps:

		Fair Value Measurements as of
	Balance Sheet Location	December 31, 2012		December 31, 2011
Interest Rate Derivatives - Designated	Non-current derivative liabilities	$	21,290	$	—
Interest Rate Derivatives - De-designated	Non-current derivative liabilities	5,134		—

The following table (in thousands) shows our Interest Rate Derivatives market adjustments recorded during the year endedDecember 31, 2012:

	Gain (Loss) in Other Comprehensive Income					Gain (Loss) Reclassified from Accumulated OCI into Interest Expense (Effective Portion)				Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	2012			2011		2012		2011		2012		2011
Interest Rate Derivatives - Designated	$	(21,290	)	$	—	$	—	$	—	$	—	$	—
Interest Rate Derivatives - De-designated	(5,814		)	—		—		—		—		—
Interest Rate Derivatives - Settlements	(136		)	—		—		—		—		—

The following table (in thousands) shows the changes in the fair value of our De-designated Interest Rate Derivatives recorded in derivative gain on our Consolidated Statements of Operations during the years endedDecember 31, 2012, 2011 and 2010:

	Year Ended December 31,
	2012		2011		2010
Interest Rate Derivatives - De-designated	$	679	$	—	$	—

Balance Sheet Presentation

The Company's commodity and interest rate derivatives are presented on a net basis on our Consolidated Balance Sheets as described above. The following table (in thousands) shows the fair value of our derivatives outstanding on a gross basis:

	December 31, 2012		December 31, 2011
Commodity Derivatives:
Assets	$	607	$	1,942
Liabilities	474		1,747
Interest Rate Derivatives:
Assets - designated	$	17,512	$	—
Assets - de-designated	4,283		—
Liabilities - designated	38,729		—
Liabilities - de-designated	9,491		—

Other Financial Instruments

The estimated fair value of our other 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.

Other Financial Instruments (in thousands):

	December 31, 2012				December 31, 2011
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2013 Notes (1)	$	—	$	—	$	550,000	$	555,500
2016 Notes, net of discount (1)	1,647,113		1,824,177		1,642,418		1,650,630
2020 Notes (1)	420,000		437,850		—		—
Liquefaction Credit Facility (2)	100,000		100,000		—		—

(1) The Level 2 estimated fair value was based on quotations obtained from broker-dealers who make markets in these and similar instruments based on the closing trading prices on December 31, 2012 and 2011, as applicable.

(2) The Level 3 estimated fair value of the Liquefaction Credit Facility as of December 31, 2012 was determined to be the carrying amount due to our ability to call this debt at anytime without penalty.

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Description of Equity Interests (Details) (USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended	1 Months Ended			12 Months Ended			0 Months Ended	1 Months Ended			12 Months Ended		0 Months Ended	1 Months Ended					0 Months Ended	12 Months Ended		0 Months Ended
	Mar. 26, 2007	Sep. 30, 2012	May 31, 2012	Sep. 30, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Class B Unit [Member]	Mar. 26, 2007 Common Units	Sep. 30, 2012 Common Units	Sep. 30, 2011 Common Units	Jan. 31, 2011 Common Units	Dec. 31, 2012 Common Units	Dec. 31, 2011 Common Units	May 31, 2007 Cheniere Subsidiary Holdings, LLC [Member] Subordinated Units	Sep. 30, 2011 Cheniere Common Units Holding, LLC [Member] Common Units	May 31, 2012 Blackstone CQP Holdco LP [Member]	May 31, 2012 Blackstone CQP Holdco LP [Member] Class B Unit [Member]	May 31, 2012 Cheniere Energy, Inc. [Member]	May 31, 2012 Cheniere Energy, Inc. [Member] Class B Unit [Member]	Mar. 26, 2007 General Partner [Member]	Dec. 31, 2012 General Partner [Member]	Dec. 31, 2011 General Partner [Member]	Mar. 26, 2007 General Partner [Member] Minimum [Member]	Mar. 26, 2007 General Partner [Member] Maximum [Member]
Class of Stock [Line Items]
Partners' Capital Account, Units, Sold in Private Placement			133,300,000											135,383,831	1,100,000		100,000,000		33,300,000	3,302,045
Partners Capital Account, Units, Sold In Public Offering, Unit Price	$ 21.00	$ 15.00							$ 25.07						$ 15.25
Distributions Per General Partnership Unit Outstanding																				$ 0.425			$ 0.489
Proceeds from sale of partnership units		$ 194.0	$ 2,000.0	$ 60.0	$ 11.1	$ 9.0										$ 1,500.0		$ 500.0
Payments for Commissions					0.3
Proceeds from Partnership Contribution																					45.1	1.5
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest																				2.00%
Incentive Distribution, Distribution Per Unit																							15.00%	50.00%
At-the-Market Sale Program, Authorized Number of Units											1,000,000
Partners' Capital Account, Units, Sold in Public Offering	13,500,000							5,054,164	8,000,000	3,000,000		500,000	500,000
Unit Purchase Agreement, Units To Be Purchased																$ 1,500.0		$ 500.0
Partnership Units, Conversion Ratio, Quarterly Compounded Rate							3.50%

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Property, Plant and Equipment (Notes)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of LNG terminal costs and fixed assets, as follows (in thousands):

	December 31,
	2012			2011
LNG terminal costs
LNG terminal	$	1,641,722		$	1,637,724
LNG terminal construction-in-process	1,228,647			286
LNG site and related costs, net	156			163
Accumulated depreciation	(166,538		)	(124,409		)
Total LNG terminal costs, net	2,703,987			1,513,764
Fixed assets
Computer and office equipment	368			227
Vehicles	704			416
Machinery and equipment	1,473			1,068
Other	760			916
Accumulated depreciation	(2,397		)	(1,975		)
Total fixed assets, net	908			652
Property, plant and equipment, net	$	2,704,895		$	1,514,416

Depreciation expense related to the Sabine Pass LNG terminal totaled $42.1 million, $42.6 million and $41.8 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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
Others	15-30

In June 2012, Train 1 and Train 2 of the Liquefaction Project satisfied the criteria for capitalization. Accordingly, costs associated with the construction of Train 1 and Train 2 of the Liquefaction Project have been recorded as construction-in-process since that date. For the year ended December 31, 2012, we capitalized $35.1 million of interest expense related to the construction of Train 1 and Train 2 of the Liquefaction Project.

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Debt Issuance Costs

12 Months Ended

Dec. 31, 2012

DEBT ISSUANCE COSTS [Abstract]

Debt Issuance Costs

DEBT ISSUANCE COSTS

We have incurred debt issuance costs in connection with our long-term debt. These costs are capitalized and are being amortized over the term of the related debt. The amortization of debt issuance costs associated with the 2016 Notes and 2020 Notes was recorded as interest expense. The amortization of the debt issuance costs associated with the Liquefaction Credit Facility for the construction of Train 1 and Train 2 of the Liquefaction Project was capitalized. As of December 31, 2012, we had capitalized $220.9 million of costs directly associated with the arrangement of debt financing, net of accumulated amortization, as follows (in thousands): 

Long-Term Debt	Debt Issuance Costs		Amortization Period	Accumulated Amortization			Net Costs
Liquefaction Credit Facility	$	212,795	7 years	$	(12,728	)	$	200,067
2016 Notes	30,057		10 years	(18,030		)	12,027
2020 Notes	9,092		8 years	(237		)	8,855
Total	$	251,944		$	(30,995	)	$	220,949

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Accrued Liabilities

12 Months Ended

Dec. 31, 2012

Accrued Liabilities [Abstract]

Accrued Liabilities [Text Block]

ACCRUED LIABILITIES

As of December 31, 2012 and 2011, accrued liabilities consisted of the following (in thousands):

	December 31,
	2012		2011
Interest and related debt fees	$	16,327	$	13,732
Affiliate	5,791		3,794
LNG liquefaction costs	26,131		1,635
LNG terminal costs	977		1,122
Other	3,968		262
Total accrued liabilities (including affiliate)	$	53,194	$	20,545

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Loss Contingencies [Line Items]
Restricted net assets of consolidated subsidiaries	$ 972.4
Bechtel EPC Contract - Train One And Two [Member]
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Royalty Guarantees, Amount	3,900.0
Bechtel EPC Contract - Train Three And Four [Member]
Loss Contingencies [Line Items]
Long-term Purchase Commitment, Amount	3,769
Lump sum payment, termination prior to issuance of notice to proceed	5.0
Minimum [Member] | Bechtel EPC Contract - Train Three And Four [Member]
Loss Contingencies [Line Items]
Lump sum payment, termination prior to issuance of notice to proceed	1.0
Minimum [Member] | Royalty Agreements [Member]
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Royalty Guarantees, Amount	2.0
Maximum [Member] | Bechtel EPC Contract - Train One And Two [Member]
Loss Contingencies [Line Items]
Lump sum payment, termination prior to issuance of notice to proceed	30.0
Maximum [Member] | Bechtel EPC Contract - Train Three And Four [Member]
Loss Contingencies [Line Items]
Lump sum payment, termination after issuance of notice to proceed	30.0
Lump sum payment, termination prior to issuance of notice to proceed	2.5
Maximum [Member] | Royalty Agreements [Member]
Loss Contingencies [Line Items]
Oil and Gas Delivery Commitments and Contracts, Royalty Guarantees, Amount	$ 11.0

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Cash Distributions and Net Income (Loss) per Common Unit - Schedule of Partner Distributions Made (Details) (USD $)	0 Months Ended	1 Months Ended			3 Months Ended												12 Months Ended
	Mar. 26, 2007	Sep. 30, 2012	May 31, 2012	Sep. 30, 2011	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Dec. 31, 2012	Dec. 31, 2011
Distribution Made to Member or Limited Partner [Line Items]
Number of days after quarter end distribution is paid																	$ 45
Date paid					Nov. 14, 2012	Aug. 13, 2012	May 14, 2012	Feb. 12, 2012	Nov. 14, 2011	Aug. 12, 2011	May 13, 2011	Feb. 11, 2011	Nov. 12, 2010	Aug. 13, 2010	May 14, 2010	Feb. 12, 2010
Total distribution																	333,453,000	313,619,000
Partner units issued and sold			133,300,000
Partner units issued and sold, unit price ($US$ per unit)	$ 21.00	$ 15.00
Proceeds from sale of partnership units		194,000,000	2,000,000,000	60,000,000													11,100,000	9,000,000
Common Units
Distribution Made to Member or Limited Partner [Line Items]
Distribution per unit					0.425	0.425	0.425	0.425	0.425	0.425	0.425	0.425	0.425	0.425	0.425	0.425
Total distribution					16,783,000	13,383,000	13,323,000	13,176,000	13,176,000	11,446,000	11,335,000	11,229,000	11,227,000	11,227,000	11,227,000	11,227,000
Partner units issued and sold, unit price ($US$ per unit)		$ 25.07
Class B Unit [Member]
Distribution Made to Member or Limited Partner [Line Items]
Total distribution					0	0	0	0	0	0	0	0	0	0	0	0
Subordinated Units
Distribution Made to Member or Limited Partner [Line Items]
Distribution per unit					0.000	0.000			0.000	0.000	0.000	0.000	0.000	0.000	0.425	0.425
Total distribution					0	0			0	0	0	0	0	0	57,538,000	57,538,000
General Partner [Member]
Distribution Made to Member or Limited Partner [Line Items]
Total distribution					342,000	273,000	272,000	269,000	269,000	234,000	231,000	229,000	229,000	229,000	1,403,000	1,403,000

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Leases (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended						1 Months Ended				1 Months Ended
	Jan. 31, 2008 lease_extension	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Land [Member]	Dec. 31, 2011 Land [Member]	Dec. 31, 2010 Land [Member]	Feb. 28, 2005 Sabine Pass LNG, LP [Member] Land [Member] acre lease_extension	Jan. 31, 2005 Sabine Pass LNG, LP [Member] Land [Member] lease lease_extension	Dec. 31, 2012 Sabine Pass LNG, LP [Member] Land [Member]	Jul. 31, 2012 Sabine Pass LNG, LP [Member] Land [Member] acre	Dec. 31, 2011 Sabine Pass Liquefaction [Member] Land [Member] lease_extension acre	Nov. 30, 2011 Sabine Pass Liquefaction [Member] Land [Member] acre lease_extension
Operating Leased Assets [Line Items]
Number of land leases entered into									3
Rental expense recognized		$ 10,000,000	$ 9,200,000	$ 9,100,000	$ 2,300,000	$ 1,800,000	$ 1,700,000	$ 1,500,000				$ 257,800	$ 138,000
Initial term of the lease									30 years			30 years	5 years
Number Of Available Lease Extensions									6			6	5
Term of available extension	5 years								10 years			10 years	1 year
Acreage under lease								853			0	80.6	80.7
Lease adjustment period due to inflation										5 years
Initial term of the Tug Boat Agreement	10 years
Number of additional renewal options under the Tug Boat Agreement	2

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Leases Leases (Tables)

12 Months Ended

Dec. 31, 2012

Leases [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases

The following is a schedule by years of future minimum rental payments, excluding inflationary adjustments, required as of December 31, 2012 under the land leases and tug boat lease described below (in thousands):

Year ending December 31,	Lease Payments (2)
2013	$	9,625
2014	9,625
2015	9,604
2016	9,577
2017	9,462
Later years (1)	231,884
Total minimum payments required	$	279,777

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

(2) Lease payments for Sabine Pass LNG’s tug boat lease represent its lease payment obligation and do not take into account the $112.8 million of sublease payments Sabine Pass LNG will receive from its three TUA customers that effectively offset these lease payment obligations, as discussed below.

La

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Financial Instruments - Interest Rate Derivatives Market Adjustments (Details) (Interest Rate Contract [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	$ (21,290)	$ 0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	0
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0
Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(5,814)	0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	0
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0
Gain (Loss) on Settlement of Derivative Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	(136)	0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	0
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ 0	$ 0

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Leases

12 Months Ended

Dec. 31, 2012

Leases [Abstract]

Leases

LEASES

During the years ended December 31, 2012, 2011 and 2010, we recognized rental expense for all operating leases of $10.0 million, $9.2 million and $9.1 million, respectively.

The following is a schedule by years of future minimum rental payments, excluding inflationary adjustments, required as of December 31, 2012 under the land leases and tug boat lease described below (in thousands):

Year ending December 31,	Lease Payments (2)
2013	$	9,625
2014	9,625
2015	9,604
2016	9,577
2017	9,462
Later years (1)	231,884
Total minimum payments required	$	279,777

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

(2) Lease payments for Sabine Pass LNG’s tug boat lease represent its lease payment obligation and do not take into account the $112.8 million of sublease payments Sabine Pass LNG will receive from its three TUA customers that effectively offset these lease payment obligations, as discussed below.

Land Leases

In January 2005, Sabine Pass LNG exercised its 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 six10-year extensions with similar terms as the initial term. In February 2005, two of the three leases were amended, increasing the total acreage under lease to 853 acres and increasing the annual lease payments to $1.5 million.  In July 2012, Sabine Pass LNG entered into an additional land lease, thereby increasing the total acreage under lease to 883 acres.  The annual lease payments are adjusted for inflation every 5 years based on a consumer price index, as defined in the lease agreements.

In November 2011, Sabine Pass Liquefaction entered into a land lease of 80.7 acres to be used as the laydown area during the construction of the Liquefaction Project. The annual lease payment is $138,000. The lease has an initial term of five years, with options to renew for five1-year extensions with similar terms as the initial term. In December 2011, Sabine Pass Liquefaction entered into a land lease of 80.6 acres to be used for the site of the Liquefaction Project. The annual lease payment is $257,800. The lease has an initial term of 30 years, with options to renew for six10-year extensions with similar terms as the initial term. The annual lease payment is adjusted for inflation every 5 years based on a consumer price index, as defined in the lease agreement.

We recognized $2.3 million, $1.8 million and $1.7 million of site lease expense on our Consolidated Statements of Operations in 2012, 2011 and 2010, respectively.

Tug Boat Lease

In the second quarter of 2008, Sabine Pass LNG acquired a lease for the use of tug boats and marine services at the Sabine Pass LNG terminal as a result of its purchase of Tug Services (the "Tug Agreement").  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 5 years each.  We have determined that the Tug Agreement contains a lease for the tugs specified in the Tug Agreement.  In addition, we have concluded that the tug lease contained in the Tug Agreement is an operating lease, and as such, the equipment component of the Tug Agreement will be charged to expense over the term of the Tug Agreement as it becomes payable.

In connection with this lease acquisition, Tug Services entered into a Tug Sharing Agreement with Chevron, Total and Cheniere Marketing to provide their LNG cargo vessels with tug boat and marine services at our LNG terminal and effectively offset the cost of our lease. The Tug Sharing Agreement provides for each of our customers to pay Tug Services an annual service fee.

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Supplemental Information to Consolidated Combined Financial Statements

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data

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

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Year ended December 31, 2012:
Revenues	$	69,323		$	61,396		$	66,308		67,300
Income from operations	24,891			18,275			772			19,602
Net loss	(19,332		)	(24,861		)	(42,422		)	(63,521		)
Net income (loss) per common unit—basic and diluted	$	0.23		$	0.17		$	0.04		$	(0.06	)
Year ended December 31, 2011:
Revenues	$	74,450		$	73,609		$	64,907		$	70,824
Income from operations	41,127			36,932			29,523			37,044
Net loss	(2,209		)	(6,868		)	(14,479		)	(7,463		)
Net income per common unit—basic and diluted	$	0.35		$	0.32		$	0.29		$	0.30

The sum of the quarterly net income per common unit may not equal the full year amount as the computations of the weighted average common unit outstanding for basic and diluted shares outstanding for each quarter and the full year are performed independently.

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Financial Instruments - Notional Amounts of Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Derivative [Line Items]
Percentage of Debt Hedged by Interest Rate Derivatives	75.00%
Variable Rate Loan converted to Fixed Rate	$ 20.0
Notional Amount of Interest Rate Derivatives	2,900.0
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Average Fixed Interest Rate	1.98%
Notional Amount of Interest Rate Derivatives	0
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Average Fixed Interest Rate	1.98%
Notional Amount of Interest Rate Derivatives	0
Maximum [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	0
Maximum [Member] | Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Notional Amount of Interest Rate Derivatives	$ 0

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Restricted Cash and Cash Equivalents (Details) (USD $)			12 Months Ended						12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Senior Notes [Member] Rate	Nov. 30, 2006 Senior Notes [Member]	Dec. 31, 2012 Sabine Pass LNG, LP [Member] Senior Notes Interest Payments [Member]	Dec. 31, 2011 Sabine Pass LNG, LP [Member] Senior Notes Interest Payments [Member]	Dec. 31, 2012 Sabine Pass LNG, LP [Member] Debt Service Reserve Fund [Member]	Dec. 31, 2011 Sabine Pass LNG, LP [Member] Debt Service Reserve Fund [Member]	Dec. 31, 2012 Sabine Pass LNG, LP [Member] Senior Notes [Member]	Dec. 31, 2012 2013 And 2016 Senior Secured Notes [Member] Sabine Pass LNG, LP [Member] Senior Notes [Member]	Oct. 31, 2012 2020 Notes [Member] Senior Notes [Member]	Dec. 31, 2012 2020 Notes [Member] Sabine Pass LNG, LP [Member] Senior Notes [Member]	Jul. 31, 2012 Liquefaction Credit Facility [Member] Sabine Pass Liquefaction [Member]	Dec. 31, 2012 Acquisition of Non-current Assets [Member] Sabine Pass Liquefaction [Member] Debt Service Reserve Fund [Member]	Dec. 31, 2012 Payment of Liabilities [Member] Sabine Pass Liquefaction [Member] Debt Service Reserve Fund [Member]	Dec. 31, 2012 Payment For Project [Member] Sabine Pass Liquefaction [Member] Debt Service Reserve Fund [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Debt instrument principal amount				$ 2,032,000,000						$ 2,215,500,000	$ 420,000,000	$ 420,000,000	$ 3,600,000,000
Debt instrument fixed charge coverage ratio			2						2
Current restricted cash and cash equivalents	92,519,000	13,732,000			17,400,000	13,700,000									75,100,000
Non-current restricted cash and cash equivalents	$ 272,425,000	$ 82,394,000					$ 76,100,000	$ 82,400,000						$ 100,000,000		$ 96,300,000

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Consolidated Statements of Comprehensive Loss (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement of Other Comprehensive Income [Abstract]
Net income (loss)	$ (150,136)	$ (31,019)	$ 107,568
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(136)	0	0
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	(27,104)	0	0
Other Comprehensive Income (Loss), Net of Tax	(27,240)	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (177,376)	$ (31,019)	$ 107,568

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 Partners, L.P. 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

Generally, we begin capitalizing the costs of LNG terminal projects 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 terminal use agreements ("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.

Derivatives

We use derivative instruments from time to time to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory, to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal, and to hedge the exposure to volatility in a portion of the floating-rate interest payments under the Liquefaction Credit Facility. We do not offset the fair value amounts of our LNG inventory, fuel and interest rate derivatives, and collateral deposited for such contracts are not netted within the derivative fair value.  We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 8—"Financial Instruments" of our Notes to Consolidated Financial Statements.

Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivative instruments be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. We record changes in the fair value of our derivative positions 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 and interest rates change.

Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are recognized currently in earnings. Gains and losses in positions to hedge the cash flows attributable to the future sale of LNG inventory are classified as 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 have elected cash flow hedge accounting for derivatives that we use to hedge the exposure to volatility in floating-rate interest payments. Changes in fair value of derivative instruments designated as cash flow hedges, to the extent the hedge is effective, are recognized in accumulated other comprehensive loss on our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive loss into interest expense in our Consolidated Statements of Operations as the hedged item is recognized. Any change in the fair value resulting from ineffectiveness is recognized immediately as derivative gain (loss) on our Consolidated Statements of Operations. We use regression analysis to determine whether we expect a derivative to be highly effective as a cash flow hedge prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges have been effective. We perform these effectiveness tests prior to designation for all new hedges and on a quarterly basis for all existing hedges. We calculate the actual amount of ineffectiveness on our cash flow hedges using the "dollar offset" method, which compares changes in the expected cash flows of the hedged transaction to changes in the value of expected cash flows from the hedge. We discontinue hedge accounting when our effectiveness tests indicate that a derivative is no longer highly effective as a hedge; when the derivative expires or is sold, terminated or exercised; when the hedged item matures, is sold or repaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but continue to hold the derivative, we begin to apply mark-to-market accounting at that time.

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.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded as an other current asset and not netted within the derivative fair value. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

Sabine Pass LNG has entered into certain long-term TUAs with unaffiliated third parties for regasification capacity at our Sabine Pass LNG terminal. We are dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective TUAs. We have mitigated this credit risk by securing TUAs for a significant portion of our regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA.

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 property, plant and equipment for 2012, 2011 or 2010.

Income Taxes

We are not subject to either federal or state income taxes, as the partners are taxed individually on their proportionate share of our earnings. At December 31, 2012, the tax basis of our assets and liabilities was $290.6 million less than the reported amounts of our assets and liabilities.

In November 2006, Sabine Pass LNG and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass LNG and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass LNG will pay to Cheniere an amount equal to the state and local tax that Sabine Pass LNG would be required to pay if Sabine Pass LNG's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass LNG under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass LNG. The agreement is effective for tax returns due on or after January 1, 2008.

In August 2012, Sabine Pass Liquefaction and Cheniere entered into a state tax sharing agreement. Under this agreement, Cheniere has agreed to prepare and file all state and local tax returns which Sabine Pass Liquefaction and Cheniere are required to file on a combined basis and to timely pay the combined state and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass Liquefaction will pay to Cheniere an amount equal to the state and local tax that Sabine Pass Liquefaction would be required to pay if Sabine Pass Liquefaction's state and local tax liability were computed on a separate company basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass Liquefaction under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass Liquefaction. The agreement is effective for tax returns due on or after August 2012.

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 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 units, reduced estimates of future cash flows for our business 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, 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, valuations of derivative instruments 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.

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.

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:

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. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualty expected, is zero. Therefore, we have not recorded an asset retirement obligation associated with the Sabine Pass LNG terminal.

Recent Accounting Standards Not Yet Adopted

We have also considered all other newly issued accounting guidance that is applicable to our operations and the preparation of our consolidated financial statements, including that which is not yet effective. We do not believe that any such guidance will have a material impact on our consolidated financial position, results of operations or cash flows.

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Long-Term Debt - Schedule of Debt Maturities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Extinguishment of Debt [Line Items]
Total long term debt (including related parties)	$ 2,185,500	$ 2,215,500
2013	0
2014 to 2015	0
2016 to 2017	1,665,500
Thereafter	520,000
2016 Notes [Member]
Extinguishment of Debt [Line Items]
Total long term debt (including related parties)	1,665,500	1,665,500
2013	0
2014 to 2015	0
2016 to 2017	1,665,500
Thereafter	0
2020 Notes [Member]
Extinguishment of Debt [Line Items]
Total long term debt (including related parties)	420,000	0
2013	0
2014 to 2015	0
2016 to 2017	0
Thereafter	420,000
Liquefaction Credit Facility [Member]
Extinguishment of Debt [Line Items]
Total long term debt (including related parties)	100,000	0
2013	0
2014 to 2015	0
2016 to 2017	0
Thereafter	$ 100,000

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Supplemental Information to Consolidated Combined Financial Statements (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 67,300	$ 66,308	$ 61,396	$ 69,323	$ 70,824	$ 64,907	$ 73,609	$ 74,450	$ 264,327	$ 283,790	$ 399,282
Income from operations	19,602	772	18,275	24,891	37,044	29,523	36,932	41,127	63,540	144,626	280,797
Net loss	$ (63,521)	$ (42,422)	$ (24,861)	$ (19,332)	$ (7,463)	$ (14,479)	$ (6,868)	$ (2,209)	$ (150,136)	$ (31,019)	$ 107,568
Net income (loss) per common unit - basic and diluted	$ (0.06)	$ 0.04	$ 0.17	$ 0.23	$ 0.30	$ 0.29	$ 0.32	$ 0.35		$ 1.23	$ 1.70

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Schedule I - Condensed Financial Information of Registrant

12 Months Ended

Dec. 31, 2011

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Financial Information of Parent Company Only Disclosure

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—

CHENIERE ENERGY PARTNERS, L.P.

CONDENSED BALANCE SHEET

(in thousands)

	December 31,
	2012		2011
ASSETS
Current assets
Cash and cash equivalents	$	392,945	$	56,119
Advances to affiliate	—		136
Prepaid expenses and other	134		135
Total current assets	393,079		56,390
Investment in affiliates	972,395		—
Non-current receivable—affiliates	940		47,238
Other	874		—
Total assets	$	1,367,288	$	103,628
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities	$	4,480	$	3,806
Equity in losses of affiliates	—		644,841
Commitments and contingencies
Stockholders' equity (deficit)	1,362,808		(545,019		)
Total liabilities and stockholders’ deficit	$	1,367,288	$	103,628

See accompanying notes to condensed financial statements.

CONDENSED STATEMENT OF OPERATIONS

(in thousands)

	Year Ended December 31,
	2012			2011			2010
Revenues	$	—		$	—		$	—
Operating costs and expenses	18,262			13,104			14,723
Loss from operations	(18,262		)	(13,104		)	(14,723		)
Interest expense, net	12			—			—
Interest income	235			38			51
Equity income (loss) of affiliates	(132,121		)	(17,953		)	122,240
Net income (loss)	$	(150,136	)	$	(31,019	)	$	107,568

See accompanying notes to condensed financial statements.

CONDENSED STATEMENT OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2012			2011			2010
Cash flows from operating activities	$	(17,508	)	$	(13,948	)	$	(10,193	)
Cash flows from investing activities
Investment in subsidiaries	(1,832,440		)	—			(20,918		)
Other	3			—			—
Net cash used in investing activities	(1,832,437		)	—			(20,918		)
Cash flows from financing activities:
Proceeds from sale of Class B units	1,887,342			—			—
Distributions received from affiliates, net	61,529			59,910			229,608
Distributions to owners	(57,821		)	(48,149		)	(163,249		)
Proceeds from sale of partnership units	250,021			70,157			—
Affiliate receivable	46,574			(38,333		)	(8,896		)
Deferred financing costs	(874		)	—			—
Net cash provided by financing activities	2,186,771			43,585			57,463
Net increase in cash and cash equivalents	336,826			29,637			26,352
Cash and cash equivalents—beginning of year	56,119			26,482			130
Cash and cash equivalents—end of year	$	392,945		$	56,119		$	26,482

See accompanying notes to condensed financial statements.

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 Partners, L.P. ("Cheniere Partners").

In the condensed financial statements, Cheniere Partners’ 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 sheets. The gain/(loss) from operations of the affiliates is reported on a net basis as equity in net gains/(losses) of affiliates.

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

NOTE 2—SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Non-cash capital contributions (1)	$	(132,121	)	$	(17,953	)	122,240

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

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Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2012 bcf
Organization and Nature of Operations [Line Items]
Storage Capacity	16.9
Regasification capacity	4
Train nominal capacity	4.5
Cheniere Energy, Inc. [Member]
Organization and Nature of Operations [Line Items]
Ownership Interest In Limited Partnership	59.50%
Maximum [Member]
Organization and Nature of Operations [Line Items]
Volume of Vessel	265,000

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Related Party Transactions

12 Months Ended

Dec. 31, 2011

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

As of December 31, 2012 and 2011, we had $5.0 million and $0.7 million of advances to affiliates, respectively. In addition, we have entered into the following related party transactions:

LNG Terminal Capacity Agreements

Terminal Use Agreement

In November 2006, Cheniere Marketing, LLC, a wholly owned subsidiary of Cheniere ("Cheniere Marketing"), reserved approximately 2.0 Bcf/d of regasification capacity under a firm commitment terminal use agreement ("TUA") with Sabine Pass LNG and was required to make capacity reservation fee payments aggregating approximately $250 million per year for the period from January 1, 2009, through at least September 30, 2028. Cheniere guaranteed Cheniere Marketing's obligations under its TUA.

Effective July 1, 2010, Cheniere Marketing assigned its existing TUA with Sabine Pass LNG to Cheniere Investments, our wholly owned subsidiary, including all of its rights, titles, interests, obligations and liabilities in and under the TUA. After the assignment of the TUA from Cheniere Marketing to Cheniere Investments, Cheniere Investments began making its TUA payments on a monthly basis. Sabine Pass Liquefaction obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Investments of its rights, title and interest under its TUA. In connection with the assignment, Sabine Pass LNG, Sabine Pass Liquefaction and Cheniere Investments entered into a terminal use rights assignment and agreement ("TURA") pursuant to which Cheniere Investments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity payments required by the TUA to Sabine Pass LNG. We have guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under the TURA. However, the revenue earned by Sabine Pass LNG from Cheniere Investments' capacity payments under its TUA was eliminated and under its TURA is eliminated upon consolidation of our financial statements.

In connection with monetizing Cheniere Investments’ reserved capacity under its TURA during construction of the Liquefaction Project, Cheniere Marketing has entered into a variable capacity rights agreement ("VCRA") pursuant to which 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 increase our 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 its subordinated units. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs paid by Cheniere Investments under the TURA. We recorded $4.9 million, $11.2 million and $1.9 million of revenues—affiliate from Cheniere Marketing in the years endedDecember 31, 2012, 2011, and 2010, respectively, related to the VCRA.

In September 2012, Sabine Pass Liquefaction entered into a partial TUA assignment agreement with Total, whereby Sabine Pass Liquefaction will progressively gain access to Total's capacity and other services provided under Total's TUA with Sabine Pass LNG.  This agreement will provide Sabine Pass Liquefaction with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Train 5 and Train 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations of Train 3, and permit Sabine Pass Liquefaction to more flexibly manage its storage with the commencement of Train 1. Notwithstanding any arrangements between Total and Sabine Pass Liquefaction, payments required to be made by Total to Sabine Pass LNG shall continue to be made by Total to Sabine Pass LNG in accordance with its TUA.

LNG Sale and Purchase Agreement ("SPA")

Cheniere Marketing has entered into an SPA with Sabine Pass Liquefaction to purchase, at its option, any excess LNG produced that is not committed to non-affiliate parties, for up to a maximum of 104,000,000 MMBtu per annum produced from Train 1 through Train 4 of the Liquefaction Project. Cheniere Marketing may purchase incremental LNG volumes at a price of 115% of Henry Hub plus up to $3.00 per MMBtu for the first 36,000,000 MMBtu of the most profitable cargoes sold each year by Cheniere Marketing, and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing.

LNG Lease Agreement

In September 2011, Cheniere Investments entered into an agreement in the form of a lease (the "LNG Lease Agreement")with Cheniere Marketing that enables Cheniere Investments to supply the Sabine Pass LNG terminal with LNG to maintain proper LNG inventory levels and temperature. The LNG Lease Agreement also enables Cheniere Investments to hedge the exposure to variability in expected future cash flows of its LNG inventory. Under the terms of the LNG Lease Agreement, Cheniere Marketing funds all activities related to the purchase and hedging of the LNG, and Cheniere Investments reimburses Cheniere Marketing for all costs and assumes full price risk associated with these activities.

As a result of Cheniere Investments assuming full price risk associated with the LNG Lease Agreement, LNG inventory purchased by Cheniere Marketing under this arrangement is classified as LNG inventory—affiliate on our Consolidated Balance Sheets, and is recorded at cost and subject to lower-of-cost-or-market ("LCM") adjustments at the end of each period. LNG inventory—affiliate cost is determined using the average cost method. Recoveries of losses resulting from interim period LCM adjustments are made due to market price recoveries on the same LNG inventory—affiliate in the same fiscal year and are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. Gains or losses on the sale of LNG inventory—affiliate and LCM adjustments are recorded as revenues on our Consolidated Statements of Operations. As of December 31, 2012, we had 1,369,000 MMBtu of LNG inventory—affiliate recorded at $4.4 million on our Consolidated Balance Sheets, and as of December 31, 2011, we had 1,527,000 MMBtu of LNG inventory—affiliate recorded at $4.4 million on our Consolidated Balance Sheets. During the years endedDecember 31, 2012 and 2011, we recognized a loss of $1.4 million and $11.4 million, respectively, as a result of LCM adjustments to our LNG inventory—affiliate.

Cheniere Marketing has entered into financial derivatives, on our behalf, to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory under the LNG Lease Agreement. The fair value of these derivative instruments at December 31, 2012 and 2011 was $0.2 million and $1.6 million, respectively, and was classified as other current assets on our Consolidated Balance Sheets. Changes in the fair value of these derivative instruments are classified as revenues on our Consolidated Statements of Operations. We recorded revenues of $1.0 million and $2.3 million related to LNG inventory—affiliate derivatives in the years endedDecember 31, 2012 and 2011, respectively.

Service Agreements

During the years endedDecember 31, 2012, 2011 and 2010, we recorded general and administrative expense—affiliate of $53.5 million, $19.0 million and $15.9 million, respectively, under the following service agreements.

Cheniere Partners Services Agreement

We have entered into a services agreement with Cheniere LNG Terminals, Inc. ("Cheniere Terminals"), a wholly owned subsidiary of Cheniere, pursuant to which we pay Cheniere Terminals a quarterly non-accountable overhead reimbursement charge of $2.8 million (adjusted for inflation) for the provision of various general and administrative services for our benefit. In addition, we reimburse Cheniere Terminals for all audit, tax, legal and finance fees incurred by Cheniere Terminals that are necessary to perform the services under the agreement.

Sabine Pass LNG O&M Agreement

Sabine Pass LNG has entered into a long-term operation and maintenance agreement (the "Sabine Pass LNG O&M Agreement") with a wholly owned subsidiary of Cheniere pursuant to which we receive all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. Sabine Pass LNG is required to pay a fixed monthly fee of $130,000 (indexed for inflation) under the agreement, and the counterparty is entitled to a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between Sabine Pass LNG and the counterparty at the beginning of each operating year. In addition, Sabine Pass LNG is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses.

Sabine Pass LNG MSA

Sabine Pass LNG has entered into a long-term management services agreement (the "Sabine Pass LNG MSA") with Cheniere Terminals, pursuant to which Cheniere Terminals manages the operation of the Sabine Pass LNG receiving terminal, excluding those matters provided for under the O&M Agreement. Sabine Pass LNG is required to pay Cheniere Terminals a monthly fixed fee of $520,000 (indexed for inflation).

Sabine Pass Liquefaction O&M Agreement

In May 2012, Sabine Pass Liquefaction entered into an operation and maintenance agreement (the "Liquefaction O&M Agreement") with a wholly owned subsidiary of Cheniere and our general partner pursuant to which we receive all of the necessary services required to construct, operate and maintain the liquefaction facilities. Before the liquefaction facilities are operational, the services to be provided include, among other services, obtaining governmental approvals on behalf of Sabine Pass Liquefaction, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparing status reports. After the liquefaction facilities are operational, the services include all necessary services required to operate and maintain the liquefaction facilities.

Before the liquefaction facilities are operational, in addition to reimbursement of operating expenses, Sabine Pass Liquefaction is required to pay a monthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed while the liquefaction facilities are operational, Sabine Pass Liquefaction will pay in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect to such Train.

Sabine Pass Liquefaction MSA

In May 2012, Sabine Pass Liquefaction entered into a management services agreement (the "Liquefaction MSA") with a wholly owned subsidiary of Cheniere pursuant to which such subsidiary was appointed to manage the construction and operation of the liquefaction facilities, excluding those matters provided for under the Liquefaction O&M Agreement. The services to be provided include, among other services, exercising the day-to-day management of Sabine Pass Liquefaction's affairs and business, managing Sabine Pass Liquefaction's regulatory matters, managing bank and brokerage accounts and financial books and records of Sabine Pass Liquefaction's business and operations, and providing contract administration services for all contracts associated with the liquefaction facilities. Sabine Pass Liquefaction will pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. After substantial completion of each Train, Sabine Pass Liquefaction pays a fixed monthly fee of $541,667 for services with respect to such Train.

Agreement to Fund Sabine Pass LNG's Cooperative Endeavor Agreements

In July 2007, Sabine Pass LNG executed Cooperative Endeavor Agreements ("CEAs") with various Cameron Parish, Louisiana taxing authorities that allow them to collect certain annual property tax payments from Sabine Pass LNG in 2007 through 2016. This ten-year initiative represents an aggregate $25.0 million commitment and will make resources available to the Cameron Parish taxing authorities on an accelerated basis in order to aid in their reconstruction efforts following Hurricane Rita. In exchange for Sabine Pass LNG's payments of annual ad valorem taxes, Cameron Parish will grant Sabine Pass LNG a dollar for dollar credit against future ad valorem taxes to be levied against the Sabine Pass LNG terminal starting in 2019. In September 2007, Sabine Pass LNG modified its TUA with Cheniere Marketing, pursuant to which Cheniere Marketing would pay Sabine Pass LNG additional TUA revenues equal to any and all amounts payable under the CEAs in exchange for a similar amount of credits against future TUA payments it would owe Sabine Pass LNG under its TUA starting in 2019. In June 2010, Cheniere Marketing assigned its existing TUA to Cheniere Investments and concurrently entered into a VCRA, allowing Cheniere Marketing to monetize Cheniere Investments' capacity under the TUA after the assignment. In July 2012, Cheniere Investments entered into an amended and restated VCRA with Cheniere Marketing in order for Cheniere Investments to monetize the capacity rights granted under the TURA during construction of the Liquefaction Project. The amended and restated VCRA provides that Cheniere Marketing will continue to fund the CEAs during the term of the amended and restated VCRA and, in exchange, Cheniere Marketing will receive any future credits.

On a consolidated basis, these TUA payments were recorded to other assets, and payments from Cheniere Marketing that Sabine Pass LNG utilized to make the ad valorem tax payments were recorded as deferred revenue. As of December 31, 2012 and 2011, we had $14.7 million and $12.3 million of other non-current assets and non-current deferred revenue resulting from Sabine Pass LNG's ad valorem tax payments and the advance TUA payments received from Cheniere Marketing, respectively.

Contracts for Sale and Purchase of Natural Gas and LNG

Sabine Pass LNG is able to sell and purchase natural gas and LNG under an agreement with Cheniere Marketing. Under this agreement, Sabine Pass LNG purchases natural gas or LNG from Cheniere Marketing at a sales price equal to the actual purchase cost paid by Cheniere Marketing to suppliers of the natural gas or LNG, plus any third-party costs incurred by Cheniere Marketing in respect of the receipt, purchase, and delivery of the natural gas or LNG to the Sabine Pass LNG terminal.

Sabine Pass LNG recorded $2.8 million, $4.2 million and $2.8 million of natural gas and LNG purchased from Cheniere Marketing under this agreement in the years endedDecember 31, 2012, 2011 and 2010, respectively. Sabine Pass LNG recorded $2.8 million, zero and zero of natural gas sold to Cheniere Marketing under this agreement in the year ended the December 31, 2012, 2011 and 2010, respectively.

LNG Terminal Export Agreement

In January 2010, Sabine Pass LNG and Cheniere Marketing entered into an LNG Terminal Export Agreement that provides Cheniere Marketing the ability to export LNG from the Sabine Pass LNG terminal.  Sabine Pass LNG recorded revenues—affiliate of $0.3 million, $0.3 million and $0.9 million pursuant to this agreement in the years endedDecember 31, 2012, 2011 and 2010, respectively.

Tug Boat Lease Sharing Agreement

In connection with its tug boat lease, Sabine Pass Tug Services, LLC, a wholly owned subsidiary of Sabine Pass LNG ("Tug Services"), entered into a tug sharing agreement with Cheniere Marketing to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. Tug Services recorded revenues—affiliate from Cheniere Marketing of $2.8 million, $2.7 million and $2.7 million pursuant to this agreement in the years endedDecember 31, 2012, 2011 and 2010, respectively.