Cheniere Energy Partners LP Annual Report 2012

Plain-text annual report

CHENIERE ENERGY PARTNERS L.P. 2012 ANNUAL REPORT On the Cover: Sabine Pass Liquefaction Construction Cheniere Energy Partners is currently developing a liquefaction project adjacent to our Sabine Pass LNG terminal with up to six liquefaction trains and nominal capacity of approximately 27 million tonnes per annum (mtpa). April 16, 2013 Dear Shareholders, The foundational changes that are transforming the global natural gas markets continue to develop, are gaining momentum and are irreversible. delivered natural gas and continues to be the fastest- growing component of the global natural gas market. Global demand for LNG is expected to grow by an average of approximately 13.4 mtpa per year through 2025, requiring more than three new natural gas liquefaction trains to be placed into service every year to keep pace with demand. Across Europe and Asia, oil indexation has been the dominant method for long-term contracting and customers of LNG projects. However, high oil prices continue to highlight the regional disparity and buyers are increasingly seeking gas market based pricing as a component of their portfolio, resulting in increased spot LNG sales. to-point agreements. In 2011 spot and short-term LNG trade increased 50% on the year to reach 61.2 mtpa or about 8.2 Bcf/d, more than 25% of the overall LNG trade. The U.S. market is deep enough to adjust to varying quantities of LNG deliveries that respond to market pricing signals and cargo diversion supplies. During the past decade, U.S. “dry” natural gas production has grown 6 Tcf, or 33.2%, to 24 Tcf in 2012. This compares to U.S. natural gas consumption growth of 3.4 Tcf, or 15.6%, over the same period. The most a 60% reduction in net imports, achieved primarily through lower imports of pipeline gas from Canada and increased exports to Mexico. The structure of LNG trade is evolving. The trend anchored in the liquidity of the U.S. gas market, and less dependent on the traditional long-term point- Unconventional gas output has grown to more than 26 Bcf/d, roughly 45% of total U.S. output, compared to 2% of total output in 2000. Improved drilling techniques have reduced the cost of unconventional gas production by 10% since 2009, and spurred an increase in oil-directed drilling. This development has an upside for future gas supply as well, as these oil wells also produce natural gas in association with crude oil, a dynamic that increases over time, further reducing the average cost of natural gas in the U.S. During the same period, demand growth for natural gas in the U.S. lagged behind production growth and this trend is expected to continue for the foreseeable future. Figures from the EIA show that over the past decade U.S. natural gas production grew at more than twice the rate of consumption. Forecasts by capital markets, we are currently working to finalize the equity and debt commitments to fund the development and construction of Trains 3 and 4. Cheniere Energy Partners also raised $1.5 billion of equity from the sale of units to Blackstone. In August 2012, Cheniere Energy Partners issued the notice to proceed to Bechtel and construction began on the first two trains of our Sabine Liquefaction Project. In December 2012 we completed the design and negotiations with Bechtel for the engineering, procurement and construction contract for Trains 3 and 4. In April 2012, Cheniere Energy Partners received Federal Energy Regulatory Commission (FERC) approval to construct Trains 1 through 4 of our Sabine Pass Liquefaction Project. the EIA show that U.S. gas production is expected to grow by 1.3% per year through 2040 compared with 0.6% growth in U.S. natural gas consumption, which will be insufficient to sustain the current pace of production growth. During the past year Cheniere faced some significant challenges but we also celebrated many successes. In April 2012, Cheniere Energy Partners received Federal Energy Regulatory Commission (FERC) approval to construct Trains 1 through 4 of our Sabine Pass Liquefaction Project. Due to the success of our Liquefaction Project, we initiated an expansion project to develop two additional trains at our Sabine Pass Terminal and on February 27, 2013, we filed an application with the FERC seeking approval to add a 5th and 6th train and to extend our Creole Trail Pipeline. This expansion project would provide up to an additional 9.0 mtpa of liquefaction capacity for a total of 27 mtpa of LNG export volumes at the terminal. On July 31, 2012 Cheniere Energy Partners, through a syndication of 21 banks, closed a $3.6 billion loan for the construction of Trains 1 and 2, which was the largest non-recourse debt financing in the U.S. in the past decade. In the midst of favorable Recently, we announced two new customers of our Sabine Pass Liquefaction Project, Total and Centrica, with each securing LNG volumes commencing with Train 5. Cheniere has successfully secured six long-term customers for our Sabine Liquefaction Project and has contracted 20 mtpa of the 27 mtpa of LNG to be developed at the terminal. In addition, Cheniere Marketing has agreed to monetize the excess LNG volumes, approximately 2 mtpa, from Trains 1 through 4. Looking ahead, we remain focused on the development of our projects and identifying additional opportunities that complement our business strategy. Sincerely, Charif Souki Chairman and CEO SABINE PASS LIQUEFACTION PROJECT Sabine Pass Today Liquefaction Project ~ 1,000 acres in Cameron Parish, LA 40 ft. ship channel; 3.7 miles from coast 2 berths; 4 dedicated tugs 5 LNG storage tanks (17 Bcfe storage) 4.3 Bcf/d peak vaporization 5.3 Bcf/d of pipeline connection to the U.S. pipeline network Six liquefaction trains / 4.5 mtpa each Designed with ConocoPhillips Optimized Cascade® technology Construction contracts w/ Bechtel Six GE LM250+ G4 gas turbine driven refrigerant compressors per train Gas treating / environmental compliance UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549Form 10-KxANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2012ORoTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934For 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 ororganization) (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) 375-5000Securities registered pursuant to Section 12(b) of the Act:Common Units Representing LimitedPartner InterestsNYSE 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. Yes o No xIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No xIndicate 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 thepreceding 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 90days. Yes x No oIndicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to besubmitted 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 postsuch files). Yes x No oIndicate 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 theregistrant’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. xIndicate 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 xNon-accelerated filer o Smaller reporting company o(Do not check if a smaller reporting company) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No xThe 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.PTABLE OF CONTENTSPART I1Items 1. and 2. Business and Properties1General1Our Business Strategy2Our Business2Market Factors and Competition8Subsidiaries9Employees and Labor Relations9Available Information9Item 1A. Risk Factors11Risks Relating to Our Financial Matters11Risks Relating to Our Business13Risks Relating to Our Cash Distributions23Risks Relating to an Investment in Us and Our Common Units25Risks Relating to Tax Matters30Item 1B. Unresolved Staff Comments33Item 3. Legal Proceedings33Item 4. Mine Safety Disclosure33PART II33Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities33Item 6. Selected Financial Data38Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation39Introduction39Overview of Business39Overview of Significant Events39Liquidity and Capital Resources40Contractual Obligations47Results of Operations48Off-Balance Sheet Arrangements49Summary of Critical Accounting Policies and Estimates49Recent Accounting Standards52Item 7A. Quantitative and Qualitative Disclosures about Market Risk53Item 8. Financial Statements and Supplementary Data54Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure89Item 9A. Controls and Procedures89Item 9B. Other Information89PART III91Item 10. Directors, Executive Officers of Our General Partner and Corporate Governance91Item 11. Executive Compensation94Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Unitholder Matters97Item 13. Certain Relationships and Related Transactions, and Director Independence99Item 14. Principal Accountant Fees and Services101PART IV101Item 15. Exhibits and Financial Statement Schedules101iCAUTIONARY STATEMENTREGARDING FORWARD-LOOKING STATEMENTSThis annual report contains certain statements that are, or may be deemed to be, "forward-looking statements" within the meaning of Section 27A of theSecurities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Allstatements, 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 naturalgas ("LNG") imports into or exports from North America and other countries worldwide, regardless of the source of such information, or thetransportation 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 andconstruction ("EPC") contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, andanticipated costs related thereto;•statements regarding any agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received andthe anticipated timing thereof, and statements regarding the amounts of total LNG regasification, liquefaction or storage capacities that are, or maybecome 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 ofthis 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 thosediscussed in "Risk Factors." All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by theserisk factors.iiDEFINITIONS 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 liquidvolume) 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 contractfor 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 PROPERTIESGeneral We are a Delaware limited partnership formed by Cheniere Energy, Inc. ("Cheniere"). Through our wholly owned subsidiary, Sabine Pass LNG, weown and operate the regasification facilities at the Sabine Pass LNG terminal located on the Sabine Pass deep water shipping channel less than four miles fromthe Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, twodocks that can accommodate vessels of up to 265,000 cubic meters and vaporizers with regasification capacity of approximately 4.0 Bcf/d. Approximatelyone-half of the LNG receiving capacity at the Sabine Pass LNG terminal is contracted to two multinational energy companies. We are developing natural gasliquefaction facilities (the "Liquefaction Project") at the Sabine Pass LNG terminal adjacent to the existing regasification facilities through a wholly ownedsubsidiary, Sabine Pass Liquefaction. Unless the context requires otherwise, references to "Cheniere Partners", "we", "us" and "our" refer to Cheniere EnergyPartners, L.P. and its subsidiaries, including Sabine Pass LNG and Sabine Pass Liquefaction. 1The following diagram depicts our abbreviated capital structure, including our ownership of Sabine Pass LNG and Sabine Pass Liquefaction as ofFebruary 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 itsgaseous state. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant andinexpensive to produce to other areas where natural gas demand and infrastructure exist to justify economically the use of LNG. LNG is transported usinglarge oceangoing LNG tankers specifically constructed for this purpose. LNG receiving terminals offload LNG from LNG tankers, store the LNG prior toprocessing, 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 ourstrategy 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 withthe Liquefaction Project;•developing business relationships for the marketing of additional long-term and short-term agreements for excess LNG volumes at the Sabine PassLNG terminal that have not been sold to our long-term customers, and for long-term and short-term contracts for potential future projects at othersites; and•expanding our existing asset base through acquisitions from Cheniere or third parties or our own development of the Liquefaction Project orcomplementary 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 fromthe 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 terminaland 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 LNGstorage capacity of approximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved undertwo 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 LNGterminal. Capacity reservation fee TUA payments are made by Sabine Pass LNG's third-party TUA customers as follows: 2•Total Gas & Power North America, Inc. ("Total") has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthlycapacity 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 capacitypayments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced July 1, 2009. Chevron Corporationhas 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 isobligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year, continuing until at least 20 years afterSabine Pass Liquefaction delivers its first commercial cargo at Sabine Pass Liquefaction's facilities under construction, which may occur as early as late2015. Sabine Pass Liquefaction obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Energy Investments, LLC ("CheniereInvestments"), a wholly owned subsidiary of Cheniere Partners, of its rights, title and interest under its TUA. In connection with the assignment, Sabine PassLiquefaction, Cheniere Investments and Sabine Pass LNG entered into a terminal use rights assignment and agreement ("TURA") pursuant to which CheniereInvestments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity paymentsrequired by the TUA to Sabine Pass LNG. In an effort to monetize Cheniere Investments' reserved capacity under its TURA during construction of theLiquefaction Project, Cheniere Marketing, LLC ("Cheniere Marketing"), a wholly owned subsidiary of Cheniere, has entered into a variable capacity rightsagreement ("VCRA") pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNGthat Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. The revenue earned by Sabine Pass LNG from the capacity payments madeunder the TUA and the revenue earned by Cheniere Investments under the VCRA are eliminated upon consolidation of our financial statements. We haveguaranteed 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 willprogressively gain access to Total's capacity and other services provided under Total's TUA with Sabine Pass LNG. This agreement will provide Sabine PassLiquefaction with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Train 5 andTrain 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations ofTrain 3, and permit Sabine Pass Liquefaction to more flexibly manage its LNG storage capacity with the commencement of Train 1. Notwithstanding anyarrangements between Total and Sabine Pass Liquefaction, payments required to be made by Total to Sabine Pass LNG shall continue to be made by Total toSabine 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 FacilitiesThe Liquefaction Project is being developed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We plan to construct up tosix 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 thedevelopment 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 ConocoPhillipsOptimized Cascade® technology, a proven technology deployed in numerous LNG projects around the world. Sabine Pass Liquefaction has entered into lumpsum 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 Train4 (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 andDecember 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 ispermitted. 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 4.3As of December 31, 2012, the overall project completion for Train 1 and Train 2 was approximately 18% complete. Based on our current constructionschedule, we anticipate that Train 1 will produce LNG as early as the end of 2015.CustomersAs 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 quantityof 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 fixedfee of $3.00 per MMBtu. The total expected annual contracted cash flow from BG from the fixed fee component is $723 million. In addition, SabinePass Liquefaction has agreed to make LNG available to BG to the extent that Train 1 becomes commercially operable prior to the beginning of thefirst delivery window. The obligations of BG are guaranteed by BG Energy Holdings Limited, a company organized under the laws of England andWales, 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 firstcommercial 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 guaranteedby 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 contractquantity 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 of182,500,000 MMBtu of LNG and a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of $548million. 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 of104,750,000 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 commencementof 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-affiliateparties, for up to a maximum of 104,000,000 MMBtu per annum produced from Train 1 through Train 4. Cheniere Marketing may purchase incrementalLNG 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 byCheniere Marketing, and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing.ConstructionIn November 2011, Sabine Pass Liquefaction entered into the EPC Contract (Train 1 and 2) with Bechtel. Sabine Pass Liquefaction issued a notice toproceed 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), ifSabine Pass Liquefaction fails to issue notice to proceed to Bechtel by December 31, 2013, then either Sabine Pass Liquefaction or Bechtel may terminate theEPC 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. TheTrains are in various stages of development, as described above.4The contract price of the EPC Contract (Train 1 and 2) is approximately $3.97 billion, reflecting amounts incurred under change orders throughDecember 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 $6.0billion, including financing costs and interest expense during construction. The contract price of the EPC Contract (Train 3 and 4) is $3.77 billion, onlysubject to adjustment by change order (including if Sabine Pass Liquefaction issues the notice to proceed after June 1, 2013). The cost to construct Train 3and 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 theConocoPhillips Petroleum Kenai plant built by Bechtel in 1969 in Kenai, Alaska. Bechtel has since designed and/or constructed LNG facilities using theConocoPhillips Optimized Cascade® technology in Angola, Australia, Egypt, Equatorial Guinea and Trinidad. The design and technology has been proven inover four decades of operation.Pipeline FacilitiesCheniere Creole Trail Pipeline, L.P. ("Creole Trail"), an indirect wholly owned subsidiary of Cheniere, owns the Creole Trail Pipeline, a 94-milepipeline 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, andTrunkline 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 twoother 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 TrailPipeline 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 beapproximately $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 $300million, plus any costs incurred by Creole Trail from August 2012 until the purchase date, including, if applicable, any portion of the expected $90 millionfor 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 localstatutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain andmaintain applicable permits and other authorizations. This regulatory burden increases our cost of operations and construction, and failure to comply withsuch 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 andconstruct the Sabine Pass LNG terminal, we received and are required to maintain authorization from the FERC under Section 3 of the Natural Gas Act of1938, as amended ("NGA"). The FERC's approval under Section 3 of the NGA, as well as several other material governmental and regulatory approvals andpermits, 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 anapplication for the siting, construction, expansion or operation of LNG terminals, although except as specifically provided in the EPAct, nothing in the EPActis intended to affect otherwise applicable law related to any other federal agency's authorities or responsibilities related to LNG terminals. Sabine PassLiquefaction filed an application with the FERC in January 2011 for an order under Section 3 of the NGA authorizing the siting, construction and operation ofthe Liquefaction Project, including the siting, construction and operation of Train 1 through Train 4. The FERC issued final orders in April and July52012 approving Sabine Pass Liquefaction's application. Subsequently, the FERC issued written approval to commence site preparation work for Train 1through Train 4. The FERC approval requires Sabine Pass Liquefaction to obtain certain additional FERC approvals as construction progresses. To dateSabine Pass Liquefaction has been able to obtain these approvals as needed. In October 2012, Sabine Pass Liquefaction filed an application at the FERC toamend its orders to reflect certain modifications of the Liquefaction Project. The pending modifications will require additional review by the FERC under theNational 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'sapproval 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 willbe 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 anyrules, 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 itunlawful 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 anuntrue 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 LicenseThe 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 FreeTrade 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 orSeptember 7, 2020, and another order authorizing the export of up to the equivalent of 803 Bcf per year (approximately 16 mmtpa) of domestically producedLNG 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 toexport LNG to FTA countries shall be granted by the DOE without "modification or delay". Sabine Pass Liquefaction received approval to export to FTAcountries in September 2010. FTA countries which import LNG now or will do so by 2016 include: Chile, Mexico, Singapore, South Korea and theDominican 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 periodwhereby interveners are provided the opportunity to assert that such authorization would not be consistent with the public interest. Sabine Pass Liquefactionreceived 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 alsosubject to additional federal permits, orders, approvals and consultations required by other federal agencies, including: the DOE, Advisory Council onHistoric 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 HarborsAct Permit (the "Section 10/404 Permit"), the Clean Air Act Title V Operating Permit and the Prevention of Significant Deterioration (PSD) Permit, the latter twopermits 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 wassubmitted in January 2011. The process included a public comment period which commenced in March 2011 and closed in April 2011. The revised Section10/404 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 initiallysubmitted in December 2010 and revised in March 2011. The process included a public comment period from June 2011 to August 2011 and a public6hearing 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 withthe 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, weapplied 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 filedwith the FERC in October 2012 as discussed above. In November 2012, the LDEQ issued proposed revised air permits for public comment, and commentsregarding the proposed revised air permits have been filed. We anticipate, but cannot guarantee, that the revised Title V and PSD permits will be issued duringthe 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 theliquefaction 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 andstandards 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 CommissionCongress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives marketand 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'srulemaking and enforcement authority, including the authority to establish position limits on swaps products. This legislation requires the CFTC, the SECand other regulators to promulgate rules and regulations implementing the Dodd-Frank Act. In November 2011, the CFTC adopted rules to impose newposition limits on certain core futures and equivalent swaps contracts for physical commodities, including natural gas, with exceptions for certain bona fidehedging 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 andfinalizes 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-FrankAct regulatory obligations. The CFTC's swaps reporting and recordkeeping rules are to be phased in over 180 days following October 12, 2012, depending onswap 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 berequired to comply with the Dodd-Frank Act reporting and recordkeeping rules in April 2013. In December 2012, the CFTC published final rules regardingmandatory clearing of certain interest rate swaps and certain index credit default swaps and setting compliance dates for different categories of marketparticipants, 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, mandatoryclearing requirements applicable to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use forhedging. For uncleared swaps, the Dodd-Frank Act may also require our counterparties to require that we enter into credit support documentation and/or initialand variation margin requirements; however, the CFTC's and other agencies' margin rules are not yet final and therefore the application of those provisions tous is uncertain at this time. The financial reform legislation may also cause our derivatives counterparties to spin off some of their derivatives activities to aseparate entity, which may not be as creditworthy as the current counterparty. The new legislation, and any additional regulations, may also adversely affectour existing derivative contracts and restrict our ability to monetize such contracts, cause us to restructure certain contracts, reduce the availability ofderivatives 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 relatingto the protection of the environment. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilitiesfor pollution. Many of these laws and regulations restrict or prohibit the7types, quantities and concentration of substances that can be released into the environment and can lead to substantial civil and criminal fines and penaltiesfor 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. Wemay be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtainingpermits and approvals addressing air emission-related issues. We do not believe, however, that our operations, or the construction and operations of ourproposed 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 requiresmandatory reporting of greenhouse gas ("GHG") emissions from stationary fuel combustion sources as well as all fugitive emissions throughout LNGterminals. From time to time, Congress has considered proposed legislation directed at reducing GHG emissions, and the EPA has defined GHG emissionsthresholds for requiring certain permits for new and existing industrial sources. It is not possible at this time to predict how future regulations or legislationmay address GHG emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additionaloperating 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 theconstruction of facilities located within the coastal zone. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources, andin 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 tomanage 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 stormwater runoff and fill/discharges into waters of the United States. Permits must be obtained to discharge pollutants into state and federal waters. The CWA isadministered 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 inconnection 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 CompetitionSabine Pass LNG currently does not experience competition for its terminal capacity because the entire approximately 4.0 Bcf/d of regasificationcapacity 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 competewith 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 PassLiquefaction has entered into five fixed price, 20-year LNG SPAs that will utilize substantially all of the8liquefaction capacity available from these Trains. Each customer will be required to pay an escalating fixed fee for its annual contract quantity even if it electsnot 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 PassLiquefaction will compete on the basis of price per contracted volume of LNG with other LNG liquefaction projects throughout the world. Revenues associatedwith 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 issubject to a broader array of market factors, including: changes in worldwide supply and demand for natural gas, LNG and substitute products; the relativeprices for natural gas, crude oil and substitute products in North America and international markets; economic growth in developing countries; investment inenergy 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 fuelalternatives 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 and2020, 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 456mmtpa, 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 gasmarket 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 theneeds of changing markets.While global natural gas consumption has been rising internationally, natural gas production in the United States has undergone a technologicaltransformation that has resulted in a substantial increase in annual production capacity, decrease in the cost of production, and expansion of technicallyrecoverable 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 upstreamnatural gas sector in developing new reservoirs, continuing to drive down costs and producing higher valued condensates and natural gas liquids inconjunction with natural gas production. Any such facilities will compete with other international LNG export projects principally on a price basis. Theseprojects generally require capital not only to build the marine, storage and liquefaction facilities, but also to drill wells and build processing and pipelinetransportation infrastructure. Because we rely on the natural gas market and transportation infrastructure already existing in the United States, we generallyrequire less capital expenditures than competing projects. Furthermore, because natural gas is purchased from the United States market at a Henry Hub relatedprice, we can offer LNG for sale at an alternative price to crude oil prices, thereby providing customers with an opportunity to diversify their supply portfoliosby 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 ouroperations 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 LNGterminal, the Liquefaction Project and the conduct of our business. Because our general partner has no employees, it relies on subsidiaries of Cheniere toprovide 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 operationsand the Liquefaction Project. See Note 13—"Related Party Transactions" in our Notes to Consolidated Financial Statements for a discussion of thesearrangements. Cheniere considers its current employee relations to be favorable. 9Available InformationOur common units have been publicly traded since March 21, 2007, and are traded on the NYSE MKT under the symbol "CQP". Our principalexecutive offices are located at 700 Milam Street, Suite 800, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address ishttp://www.cheniereenergypartners.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports onForm 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, theSecurities and Exchange Commission ("SEC") under the Exchange Act. These reports may be accessed free of charge through our internet website. We makeour website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated byreference 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, orany 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 theSEC.10ITEM 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 subjectare 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 ourfinancial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We mayencounter 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 couldmaterially 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 wehad $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 billionof indebtedness to finance the capital costs in connection with the construction of Train 1 and Train 2. We incur significant interest expense relating to theassets at the Sabine Pass LNG terminal and Liquefaction Project, and we anticipate needing to incur substantial additional debt and issue equity to finance theconstruction of all six trains of the Liquefaction Project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our abilityto access capital markets. Furthermore, our costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, whichcould 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 positiveoperating 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 flowused in operating activities was $26.2 million for the year ended December 31, 2012. In the future, we may incur operating losses and experience negativeoperating 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. Wecurrently 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 theexpected development periods for Train 1 would prolong, and could increase the level of, our operating losses and negative operating cash flows. Our futureliquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and bythe timing of receipt of cash flows under SPAs in relation to the incurrence of project and operating expenses. Moreover, many factors (including factorsbeyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches ofagreements. Our ability to generate positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully and timelycomplete 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 coulddilute our unitholders' proportionate indirect interests in our assets, business operations, Liquefaction Project and other projects, and couldadversely affect the market price of our common units.11We have pursued and are pursuing a number of alternatives in order to generate needed amounts of cash, including potential issuances and sales ofadditional equity or equity-related securities by us. Such sales, in one or more transactions, could dilute our unitholders' proportionate indirect interests in ourassets, business operations and proposed projects, including the Liquefaction Project. In addition, such sales, or the anticipation of such sales, couldadversely 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 wehave 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 withSabine Pass LNG and agreed to pay us approximately $125 million annually, and, upon satisfaction of the conditions precedent to payment thereunder, byBG, Gas Natural Fenosa, KOGAS, GAIL and Total, each of which has entered into an SPA with Sabine Pass Liquefaction and agreed to pay usapproximately $723 million, $454 million, $548 million, $548 million and $314 million annually, respectively. We are dependent on each customer'scontinued 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 underits TUA or SPA, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adverselyaffected, 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 SabinePass LNG terminal experiences a force majeure delay for longer than 18 months, fails to redeliver a specified amount of natural gas in accordance with thecustomer's redelivery nominations or fails to accept and unload a specified number of the customer's proposed LNG cargoes. Sabine Pass LNG may not beable 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, withoutlimitation: (i) upon the occurrence of certain events of force majeure; (ii) if we fail to make available specified scheduled cargo quantities; (iii) delays in thecommencement of commercial operations; and (iv) if the conditions precedent contained in the SPAs are not met or waived by specified dates. We may not beable 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 andoption contracts traded or cleared on the Intercontinental Exchange and NYMEX, or over-the-counter options and swaps with other natural gas merchants andfinancial 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 priceschange.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 andentities, 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 (the12"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 oncertain core futures and equivalent swaps contracts for physical commodities, including natural gas, with exceptions for certain bona fide hedgingtransactions, 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 ofthis 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 swapsand setting compliance dates for different categories of market participants, the earliest of which is March 2013. The CFTC has not yet proposed any rulesrequiring the clearing of any other classes of swaps, including physical commodity swaps. Although we expect to qualify for the end-user exception from theclearing requirement for our swaps, mandatory clearing requirements applicable to other market participants, such as swap dealers, may change the cost andavailability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or other regulators may require our counterparties to require thatwe enter into credit support documentation and/or post initial and variation margin as collateral; however, the proposed margin rules are not yet final, andtherefore the application of those provisions to us is uncertain at this time. The financial reform legislation may also cause our derivatives counterparties tospin 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 newregulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect ouravailable liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduceour 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 facilitiesface 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 terminaladjacent 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. OurSPAs with KOGAS, GAIL and Total contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessaryfinancing arrangements and making a final investment decision to construct Train 3, Train 4 or Train 5, respectively. If these conditions are not met byDecember 31, 2013 with respect to KOGAS and GAIL and June 30, 2015 with respect to Total, the applicable party may terminate the respective SPA. Inaddition, 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 contractquantity 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 dateof 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 MMBtucommencing 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 theearliest. Even if successfully constructed, our proposed liquefaction facilities would be subject to the operating risks described herein. Accordingly, there aremany risks associated with the Liquefaction Project, and if we are not13successful 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 costsand delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity andprospects. The actual construction costs of the Trains may be significantly higher than our current estimates as a result of many factors, including change ordersunder existing or future engineering, procurement and construction contracts. We do not have any prior experience in constructing liquefaction facilities, andno liquefaction facilities have been constructed and placed in service in the United States in over 40 years. As construction progresses, we may decide or beforced 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 arerequired 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 toconstruct our proposed liquefaction facilities within the expected cost parameters, and the ability of those contractors to perform their obligationsunder 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 existingregasification 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 Bechtelor any future engineering, procurement and construction contract related to additional Trains, could increase the cost of completion beyond the amounts thatwe estimate, which could require us to obtain additional sources of financing to fund our operations until the Liquefaction Project is constructed (which couldcause further delays). Our ability to obtain financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factorsbeyond 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, wemay have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, contracts, financialcondition, 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 revenuesprojected therefrom or cause a loss of one or more customers in the event of significant delays. As a result, any significant construction delay, whatever thecause, 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 obtainsufficient funding, we may be unable to implement or complete our business plan and our business may ultimately be unsuccessful.14 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 acost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in development of additional Trains, and wemay 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 anyincreases 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 oneor more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effecton 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 PassLNG's TUA customers have the obligation to procure LNG if necessary for the Sabine Pass LNG terminal to maintain its cryogenic state. If theyfail 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 cryogenicreadiness of the terminal. In the event that aggregate minimum inventory levels are not maintained, Sabine Pass LNG has the right to procure a cryogenicreadiness cargo, and to the extent that the TUA customers have failed to maintain their minimum inventory levels, be reimbursed by each TUA customer fortheir 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 sufficientworking 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 theregasified LNG.Sabine Pass LNG may be required to purchase natural gas to provide fuel at the Sabine Pass LNG terminal, which would increase operatingcosts 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 asfuel 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 beinsufficient 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 andrisk 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, higherconstruction costs, and the deferral of the dates on which payments are due to Sabine Pass Liquefaction under the SPAs, all of which couldadversely affect us. In August and September of 2005, Hurricanes Katrina and Rita damaged coastal and inland areas located in Texas, Louisiana, Mississippi andAlabama, resulting in the temporary suspension of construction of the Sabine Pass LNG terminal. In September 2008, Hurricane Ike struck the Texas andLouisiana 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 damageto, or interruption of operations at, the Sabine Pass LNG terminal and related infrastructure, as well as delays or cost increases in the construction and thedevelopment 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 andoperation 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 andpermits, 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 thesiting, construction and operation of four Trains, the FERC order requires us to obtain certain additional approvals in conjunction with ongoing constructionand 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 of15the 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 potentialinterventions 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 andmaintain 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 andmaintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis, and failure to obtain and maintainany of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity andprospects. We are entirely dependent on Cheniere, including employees of Cheniere and its subsidiaries, for key personnel, and a loss of key personnel couldhave 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 PassLNG terminal operations and Liquefaction Project construction. We have contracted with subsidiaries of Cheniere to provide the personnel necessary for theoperation, maintenance and management of the Sabine Pass LNG terminal and construction of the Liquefaction Project. We face competition for these highlyskilled employees in the immediate vicinity of the Sabine Pass LNG terminal and more generally from the Gulf Coast hydrocarbon processing andconstruction industries. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulationscould make it more difficult to attract and retain personnel and could require an increase in the wage and benefits packages that are offered, thereby increasingour 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 policieson any personnel, and our general partner does not have any employment contracts or other agreements with key personnel binding them to provide servicesfor 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 futuresuccess 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 CheniereMarketing. We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, Cheniere Investments has entered into a VCRA withCheniere Marketing, under which Cheniere Marketing will be able to derive economic benefits to the extent it assists Cheniere Investments in commercializingCheniere Investments' access to capacity at the Sabine Pass LNG terminal through its TURA with Sabine Pass Liquefaction, which has a TUA with SabinePass 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-affiliateparties, 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 interestbetween 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 andgas balancing agreements with one or more Cheniere-affiliated natural gas pipelines as well as other agreements and arrangements that cannot now beanticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interestwill 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 thenegotiated terms and timetable of their respective agreement for any reason or terminates their agreement, we would be required to engage a substitute serviceprovider. 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 highlydependent on Bechtel's and our other contractors' performance under their agreements. Bechtel's and our other contractors' ability to perform successfullyunder their agreements is dependent on a number of factors, including their ability to:•design and engineer each Train to operate in accordance with specifications;16•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 arebeyond 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 itsobligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable liquefaction facility, and anyliquidated 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 ofBechtel and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein. Furthermore, we mayhave disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies undertheir contracts and increase the cost of the applicable liquefaction facility or result in a contractor's unwillingness to perform further work on the LiquefactionProject. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason orterminates 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 andperformance capabilities of our proposed liquefaction facilities. If any Train, when actually constructed, fails to have the capacity ratings and performancecapabilities that we intend, our estimates may not be accurate. Failure of any of our Trains to achieve our intended capacity ratings and performancecapabilities 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, thiscould 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 TrailPipeline. If the construction of new or modified pipeline connections is not completed on schedule or any pipeline connection were to become unavailable forcurrent 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 obligationscould 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, whichcould 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 notbe able to purchase or receive physical delivery of sufficient quantities of natural gas to satisfy those delivery obligations, which may provide affected SPAcustomers with the right to terminate their SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could have amaterial 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.17The operation of the Sabine Pass LNG terminal, and the construction and operation of the Liquefaction Project, is and will be subject to the inherentrisks 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 ourfacilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependentface 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 insurancein the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverseeffect 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 adverseeffect 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 naturalgas 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 andsubject 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 adverselyaffect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cashflows, 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 ourcustomers 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 LNGimport 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 SabinePass 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;18•changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which mayreduce the demand for natural gas;•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, whichmay 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 tobe imported into North America, to procure customers for LNG or regasified LNG, or to procure natural gas to be liquefied and exported to internationalmarkets, 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 adverselyaffect 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 abundantsupply of natural gas and recent discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into asignificant 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 somedomestic supplies of natural gas, or other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gashave recently been and may continue to be discovered in North America, which could further increase the available supply of natural gas and could result innatural 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 UnitedStates, 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 ata lower cost than the cost of other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas haverecently been and may continue to be discovered outside North America, which could further increase the available supply of natural gas and could result innatural 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 alsoimpede the willingness or ability of LNG suppliers and merchants in such countries to import or export LNG from or to the United States. Furthermore, someforeign 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 acompetitive supply alternative to local natural gas, oil and other alternative energy sources could adversely affect the ability of our customers to deliver LNGfrom 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 Statesgenerally, or to the Sabine Pass LNG terminal or from our proposed liquefaction facilities specifically, could have a material adverse effect on our customersand 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 couldhave a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.19Commercial development of an LNG facility takes a number of years, requires a substantial capital investment and may be delayed by factors suchas:•increased construction costs;•economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects oncommercially 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 bedelayed 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 transportationrequirements 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 andTrain 2 but not for additional Trains. We plan to secure additional pipeline transportation capacity but we may not be able to do so on commerciallyreasonable 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 ourbusiness, 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 naturalexpiration, 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, factorsrelating to competition may prevent us from entering into a replacement SPA on economically comparable terms, or at all. Such an event could have a materialadverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affectpotential 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;20•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 LNGfacilities, including one or more of the Trains, which would increase our costs and decrease our cash flows. A terrorist incident may also result in temporaryor 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 securitymeasures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility inprices for natural gas that could adversely affect our business and our customers, including their ability to satisfy their obligations to us under ourcommercial agreements. Instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability to raise capital. Thecontinuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on theirultimate 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 additionaloperating 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 toair, 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 OilPollution 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 andoperation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reportsrelated to our compliance. Violation of these laws and regulations could lead to substantial liabilities, fines and penalties or to capital expenditures related topollution control equipment that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidityand prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types orquantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardoussubstances 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. treatycommitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, and regulation by theEnvironmental Protection Agency (the "EPA"). In addition, as we consume natural gas at the Sabine Pass LNG terminal, this carbon tax may also be imposedon 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 PassLNG terminal through the Sabine Pass Channel, could cause additional expenditures, restrictions and delays in our business and to our proposedconstruction, 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 restrictionscould 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 andprospects. Substantially all of our anticipated revenue in 2013 will be dependent upon one facility, the Sabine Pass LNG receiving terminal located in southernLouisiana. Due to our lack of asset and geographic diversification, an adverse development at the21Sabine Pass LNG terminal, or in the LNG industry, would have a significantly greater impact on our financial condition and results of operations than if wemaintained 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 ratefluctuations. Conducting operations or making commitments and investments located, or entering into agreements with counterparties located, outside of the UnitedStates will cause us to be affected by economic, political and governmental conditions in the countries where we engage in business. Any disruption caused bythese 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 foreigncurrencies would face additional risks of fluctuating currency values and exchange rates, hard currency shortages and controls on currency exchange. Wewould be subject to the impact of foreign currency fluctuations and exchange rate changes on our reporting for results from those operations in our consolidatedfinancial statements.If we do not make acquisitions or implement capital expansion projects on economically acceptable terms, our future growth and our ability toincrease 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 LiquefactionProject. 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 forthem;•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 increasedistributions 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 orfrom third parties. However, Cheniere is not obligated to offer us any of these assets other than, in certain circumstances under an investors rights agreementwith Blackstone CQP Holdco LP, its proposed Corpus Christi liquefaction project. If Cheniere does offer us the opportunity to purchase assets, we may notbe able to successfully negotiate a purchase and sale agreement and related agreements, we may not be able to obtain any required financing for such purchaseand we may not be22able 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 adetermination that the acquisition of the assets at the proposed purchase price would not result in an increase, or a sufficient increase, in our adjusted operatingsurplus 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 theopportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our future funds andother resources. In addition, if we issue additional units in connection with future growth, our existing unitholders' interest in us will be diluted, anddistributions 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 commonunits.We are currently paying the initial quarterly distribution of $0.425 on each of our common units and the related distribution on the general partnerunits. We are currently not paying any distributions on the subordinated units. The Class B units are not entitled to receive distributions until they convertinto common units. As of December 31, 2012, we had 39,488,488 common units outstanding. The aggregate initial minimum quarterly distribution on thesecommon units and the related general partner units is $68.5 million per year. We are not currently generating sufficient operating surplus each quarter to paythe 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 tomake this distribution. We may not have sufficient operating surplus to continue paying the initial quarterly distribution on all of our common units beforeTrain 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 notcommence commercial operations as expected and the outstanding Class B units convert into common units, we may not have sufficient operating surplus tobe 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 principallywill 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.23In 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 paydistributions to us under the indentures governing the Sabine Pass LNG Senior Notes as a result of requirements for a debt service reserveaccount, a debt payment account and satisfaction of a fixed charge coverage ratio and the ability of Sabine Pass Liquefaction to paydistributions 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 ourcommon 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 quarterlydistribution on our common units below the initial quarterly distribution. Any portion of the initial quarterly distribution that is not distributed on ourcommon 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 futureindebtedness 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 otherwisesatisfy 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 onour then contracted or otherwise anticipated future cash flows available for debt service. Our TUAs with Total and Chevron, which provide substantially allof 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 belimited 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 maylimit 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 thatour subsidiaries can incur. For example, Sabine Pass LNG may not make distributions until, among other requirements, a deposit has been made in aninterest payment account for one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interestpayment, 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 issatisfied. Sabine Pass Liquefaction is likewise restricted from making distributions under agreements governing its indebtedness until, among otherrequirements, substantial completion of Train 1 and Train 2 has occurred, deposits are made into debt service reserve accounts and a debt service coverageratio 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 restrictionsin 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 requiredin the indentures governing the Sabine Pass LNG Notes (the "Sabine Pass Indentures"). In order to satisfy this fixed charge coverage ratio test, we estimate thatSabine Pass LNG's consolidated cash flow, as defined in such indentures, must be greater than approximately $340 million. Thus, TUA payments fromSabine 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 willnot be permitted by the Sabine Pass Indentures to make distributions to Cheniere Partners, which may prevent Cheniere Partners from making distributions tous 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 beneficialtransactions.24 In addition to restrictions on the ability of Sabine Pass LNG and Sabine Pass Liquefaction to make distributions or incur additional indebtedness, theagreements governing their indebtedness also contain various other covenants that may prevent them from engaging in beneficial transactions, includinglimitations 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 ourunitholders.We pay significant management fees to our general partner and its affiliates and reimburse them for expenses incurred on our behalf, which reduces ourcash available for distribution to our unitholders. See Note 13—"Related Party Transactions" in our Notes to Consolidated Financial Statements for adescription 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 onour behalf. The payment of fees to our general partner and its affiliates and the reimbursement of expenses could adversely affect our ability to pay cashdistributions 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 onprofitability. The amount of cash that we will have available for distributions will depend primarily on our cash flow, including cash reserves and working capitalor other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periodswhen 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 havesufficient cash available for distributions on our subordinated units in the future. Any further reduction in the amount of cash available for distributionscould 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 implementaccretive 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, thatwould result in sufficient cash flow to fully pay distributions to the subordinated unitholders and allow us to increase common unitholder distributions. Tofund acquisitions or capital expansion projects, we will need to pursue a variety of sources of funding, including debt and/or equity financings. Our ability toobtain 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 thefacilities 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 industryand 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 obtainfinancing, if we can obtain such financing at all. Accordingly, we may not be able to obtain financing for acquisitions or capital expansion projects on termsthat are acceptable to us, if at all. Risks Relating to an Investment in Us and Our Common Units25 Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests tothe 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 generalpartner's directors are also directors of Cheniere, and certain of our general partner's officers are officers of Cheniere. Therefore, conflicts of interest may arisebetween 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, amongothers, the following situations:•neither our partnership agreement nor any other agreement requires Cheniere to pursue a business strategy that favors us. Cheniere's directorsand 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 otherhand, 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 conflictsof 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 remediesavailable 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 opportunityto develop or acquire those assets";•our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additionalpartnership securities, and the establishment, increase or decrease in the amounts of reserves, each of which can affect the amount of cash thatis distributed to our unitholders;•our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capitalexpenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determinationcan 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 thatare 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 beindemnified 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 commonunits; 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 gasbalancing and storage agreements with one or more Cheniere-affiliated natural gas pipelines, services agreements, as well as other agreements and arrangementsthat cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additionalconflicts 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 mayacquire, construct or dispose of its proposed Corpus Christi or Creole Trail LNG terminals, its proposed pipelines or any other assets without any obligationto offer us the opportunity to purchase or construct any of those assets. In26addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to Cheniere and its affiliates. As aresult, neither Cheniere nor any of its affiliates will have any obligation to present new business opportunities to us, and they may take advantage of suchopportunities themselves. Cheniere also has significantly greater resources and experience than we have, which may make it more difficult for us to competewith 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 foractions 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 dutylaw. 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. Thisentitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration toany interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise ofits 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 mergeror 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 longas 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 ofdirectors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally beingprovided to or available from unrelated third parties or be "fair and reasonable" to us and that, in determining whether a transaction or resolutionis "fair and reasonable," our general partner may consider the totality of the relationships between the parties involved, including othertransactions 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 limitedpartners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdictiondetermining that our general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminalmatter, 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 actedin good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceedingwill 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 describedabove. Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce theprice 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 directorson an annual or other continuing basis. The board of directors of our general partner is chosen entirely by Cheniere Subsidiary Holdings, LLC ("CheniereSubsidiary Holdings"), an affiliate of Cheniere. As a result, the price at which the common units will trade could be diminished because of the absence orreduction 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 ofcommon, 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 outstandingcommon, Class B and subordinated units (including any units owned by27our 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 andunits held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted intocommon units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances wouldadversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwisehave 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 judgmentfinding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of poormanagement of the business, so the removal of the general partner because of the unitholder's dissatisfaction with our general partner's performance inmanaging 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 theconsent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or aportion 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 replacethe 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 ofany 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 unitsthen outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board ofdirectors of our general partner, cannot vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to callmeetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction ofmanagement.Our partnership agreement prohibits a unitholder (other than our general partner and its affiliates) who acquires 15% or more of our limitedpartner units without the approval of our general partner from engaging in a business combination with us for three years unless certainapprovals are obtained. This provision could discourage a change of control that our unitholders may favor, which could negatively affect theprice 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 tous prevents an interested unitholder-defined as a person (other than our general partner and its affiliates) who owns 15% or more of our outstanding limitedpartner units-from engaging in business combinations with us for three years following the time such person becomes an interested unitholder unless certainapprovals are obtained. Section 203 broadly defines "business combination" to encompass a wide variety of transactions with or caused by an interestedunitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with otherunitholders. This provision of our partnership agreement could have an anti-takeover effect with respect to transactions not approved in advance by ourgeneral 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 thepartnership that are expressly made without recourse to the general partner. We are organized under Delaware law, and we conduct business in other states. As alimited 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 ageneral 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 approvesome amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the "control" of28our business. In addition, limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearlyestablished 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 DelawareRevised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fairvalue of our assets. Delaware law provides that, for a period of three years from the date of the impermissible distribution, partners who received such adistribution 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 topartners on account of their partner interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether adistribution 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 issuean unlimited number of limited partner interests of any type without the approval of our unitholders. After the subordination period, we may issue anunlimited number of limited partner interests of any type without limitation of any kind. The issuance by us of additional common units or other equitysecurities 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 initialquarterly 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 commonunits. 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 suchsales 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 ofequity securities. Affiliates of Cheniere own 11,963,488 common units, 135,383,831 subordinated units and 33,333,334 Class B units. All of thesubordinated units will convert into common units at the29end 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 incometax 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 federalincome 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 treatedas 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 taxedagain as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon usas a corporation, the cash available for distributions to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation wouldresult 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 ourcommon 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 acorporation or otherwise subjects us to entity-level taxation for federal income tax purposes, then the minimum quarterly distribution amount and the targetdistribution 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 distributionto you. Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits andother reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and otherforms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders and, therefore, negativelyimpact 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 interpretedin a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amountand 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 oradministrative 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 modifiedby administrative, legislative or judicial interpretation at any time, causing us to be treated as a corporation for federal income tax purposes or otherwisesubjecting us to entity-level taxation. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be appliedretroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impactthe 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 theownership 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. 30We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon theownership 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 thisproration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed TreasuryRegulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention, such regulationsare 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 TreasuryRegulations 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 impactthe 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 toadministrative 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, anysuch 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 ourunitholders 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 wedistribute, 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 incomeeven 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 taxableincome 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 thatthe subordination period ends to ensure that common units issued in exchange for our subordinated units have the same economic and federal income taxcharacteristics as our other common units. Any such allocation of items of our income or gain to unitholders, which may include allocations to holders of ourcommon units, would not be accompanied by a distribution of cash to such unitholders. In addition, any such allocation of items of deduction or loss tospecific unitholders (for example, to the holder of the subordinated units) would effectively reduce the amount of items of deduction or loss that will beallocated 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 thosecommon units. Because distributions in excess of the unitholders' allocable share of our net taxable income decrease the unitholders' tax basis in their commonunits, 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 sellsuch 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 amountrealized, whether or not representing gain, may be ordinary income due to the potential recapture items, including depreciation recapture. In addition, becausethe 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 ofthe 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. Forexample, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including individual retirement accountsand other retirement plans, will be unrelated business taxable income and will be taxable to them. 31Non-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 wehave 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 maychallenge 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 allaspects 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 adjustmentsto 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. Thisdisclosure 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 businesstaxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the unitholderdoes 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 insome or all of these various jurisdictions. Furthermore, our unitholders may be subject to penalties for failure to comply with those requirements. As we makeacquisitions or expand our business, we may own property or conduct business in additional states or foreign countries that impose a personal tax or an entitylevel tax. Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of our unitholders to file all UnitedStates 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 terminationof 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 thetotal interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales ofthe 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 onefiscal 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 morethan 12 months of our taxable income or loss being includable in the unitholder's taxable income for the year of termination. Our technical terminationcurrently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership, we wouldbe 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 theunitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units. 32When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealizedgain 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 withprofessional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assetsourselves 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 maybe 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 thegeneral partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common unitsmay have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to ourintangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangibleassets, 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 ourunitholders. 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 commonunits 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 thosecommon units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during theperiod 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 theloaned 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 tothe 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 ourincome, gain, loss or deduction with respect to those common units may not be reportable by the unitholder, and any cash distributions received by theunitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk ofgain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing theircommon 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 analyzecurrent information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, asof December 31, 2012, there were no threatened or pending legal matters that would have a material impact on our consolidated results of operations, financialposition or cash flows. ITEM 4. MINE SAFETY DISCLOSURE None.PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS ANDISSUER 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. Thetable below presents the high and low daily closing sales prices per common unit, as reported by the NYSE MKT, and cash distributions to commonunitholders for the period indicated.33 High Low Cash DistributionsPer Common Unit (1) Cash DistributionsPer 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 wasreduced. 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 theLiquefaction Project. The Class B units are not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale ofsubstantially 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 underspecified circumstances, into a number of common units based on the then-applicable conversion value of the Class B units. On a quarterly basisbeginning 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 Bunits increases at a compounded rate of 3.5% per quarter, subject to an additional upward adjustment for certain equity and debt financings. Theholders 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 ofsubstantially 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 cashdistributions 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 unitsoutstanding, 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 ownedsubsidiary 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 aredependent 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 distributionsto 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 distributionpolicy regarding common and subordinated units. References therein to "unitholders" made in the context of the recipients of quarterly cash distributions referto our common unitholders and subordinated unitholders. Cash Distribution PolicyOur cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cashquarterly.Subordination Period 34During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amountequal to the initial quarterly distribution of $0.425 per quarter, plus any arrearages in the payment of the initial quarterly distribution on the common unitsfrom 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 aredeemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive anydistributions until after the common units have received the initial quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearageswill be paid on the subordinated units. The practical effect of the subordination period is to increase the likelihood that during this period there will besufficient 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 wasreduced. 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 thateach 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 theinitial 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 immediatelypreceding that date equaled or exceeded the sum of the initial quarterly distributions on all of the outstanding common units (assuming conversion ofthe Class B units), subordinated units, general partner units and any other outstanding units that are senior or equal in right of distribution to thesubordinated 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 theother common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by thegeneral 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 inexchange 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 thefirst 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 adjustedoperating surplus" (as defined below) on each outstanding common unit (assuming conversion of the Class B units), subordinated unit and anyother outstanding unit that is senior or equal in right of distribution to the subordinated units equaled or exceeded $0.638 (150% of the initialquarterly distribution) for each quarter in the four-quarter period immediately preceding that date;35•the contracted adjusted operating surplus generated during each quarter in the four-quarter period immediately preceding that date equaled or exceededthe sum of a distribution of $0.638 (150% of the initial quarterly distribution) on all of the outstanding common units (assuming conversion of theClass 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 forthe 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 tothat 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 ofprincipal, interest or premium.Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes the $30 millionoperating surplus "basket," net increases in working capital borrowings, net drawdowns of reserves of cash generated in prior periods.Definition of Contracted Adjusted Operating SurplusWe 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 withcounterparties 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 thefinal settlement price for the New York Mercantile Exchange's Henry Hub natural gas futures contract for the month in which the relevantcargo's delivery window is scheduled. Class B UnitsIn 2012, we issued Class B units, a new class of equity interests representing limited partner interests in us, in connection with the development of theLiquefaction Project. The Class B units are not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale of substantiallyall 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 ofthe 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 holdersof 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 inexcess of the initial quarterly distribution. Our general partner currently holds the incentive distribution rights but may transfer these rights separately from itsgeneral partner interest, subject to restrictions in our partnership agreement.36Assuming we do not issue any additional classes of units and our general partner maintains its 2% interest, if we have made distributions to ourunitholders from operating surplus in an amount equal to the initial quarterly distribution for any quarter, assuming no arrearages, then we will distribute anyadditional available cash from operating surplus for that quarter among the unitholders and our general partner as follows: Total Quarterly DistributionTarget Amount Marginal PercentageInterest Distributions Common andSubordinated Unitholders General PartnerInitial 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%37ITEM 6. SELECTED FINANCIAL DATA Selected financial data set forth below are derived from our audited consolidated financial statements for the periods indicated. The financial datashould be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated FinancialStatements 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 $15,000Expenses (including transactions with affiliates) 200,787 139,164 118,485 88,870 32,141Income (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 $7Restricted cash and cash equivalents (current) 92,519 13,732 13,732 13,732 235,985Non-current restricted cash and cash equivalents 272,425 82,394 82,394 82,394 137,984Non-current restricted U.S. Treasury securities — — — — 20,829Property, plant and equipment, net 2,704,895 1,514,416 1,550,465 1,588,557 1,517,507Total assets 3,748,278 1,737,300 1,743,492 1,859,473 1,978,835Long-term debt, net of discount 2,167,113 2,192,418 2,187,724 2,110,101 2,107,673Long-term debt—related party, net of discount — — — 72,928 70,661Long-term debt—affiliate — — — — 2,372Deferred revenue 21,500 25,500 29,500 33,500 37,500Deferred revenue—affiliate 14,720 12,266 9,813 7,360 4,97138ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATION Introduction The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read inconjunction with our Consolidated Financial Statements and the accompanying notes in "Financial Statements and Supplementary Data." This information isintended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion andanalysis 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 channelless than four miles from the Gulf Coast. The Sabine Pass LNG terminal includes existing infrastructure of five LNG storage tanks with capacity ofapproximately 16.9 Bcfe, two docks that can accommodate vessels of up to 265,000 cubic meters and vaporizers with regasification capacity ofapproximately 4.0 Bcf/d. Approximately one-half of the receiving capacity at the Sabine Pass LNG terminal is contracted to two multinational energycompanies. We are developing natural gas liquefaction facilities (the "Liquefaction Project") at the Sabine Pass LNG terminal adjacent to the existingregasification facilities through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"). We plan to construct up to sixTrains (each in sequence, "Train 1", "Train 2", "Train 3", "Train 4", "Train 5" and "Train 6"), which are in various stages of development. Each Trainhas 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 steadyand 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 CoastLNG, LLC ("BG"), a subsidiary of BG Group plc, (ii) an SPA with Korea Gas Corporation ("KOGAS") and (iii) an SPA with Total Gas & PowerNorth America, Inc. ("Total"), under which each customer has agreed to purchase LNG in the amount and upon the commencement of operations asdesignated in the SPAs;•Sabine Pass Liquefaction and Sabine Pass LNG received authorization from the Federal Energy Regulatory Commission ("FERC") to site, constructand operate facilities for the liquefaction and export of domestically produced natural gas at the Sabine Pass LNG terminal adjacent to the existingregasification 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 ofCheniere. Under the Agreements, we sold 100.0 million and 33.3 million Class B units to Blackstone and Cheniere, respectively, in the aggregate at aprice of $15.00 per Class B unit, for a total investment of39$2.0 billion. Proceeds from the private placements have been used to fund part of the equity portion of the costs of developing, constructing andplacing 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 portionof 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 andTrain 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 constructionof 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 FacilitiesThe Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d and aggregate LNG storage capacity ofapproximately 16.9 Bcfe. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-termthird-party TUAs, under which Sabine Pass LNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Capacityreservation 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 LNGaggregating approximately $125 million per year for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total’s obligations under itsTUA 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 capacitypayments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced July 1, 2009. Chevron Corporationhas 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 isobligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year, continuing until at least 20 years afterSabine Pass Liquefaction delivers its first commercial cargo at Sabine Pass Liquefaction's facilities under construction, which may occur as early as late2015. Sabine Pass Liquefaction obtained this reserved capacity as a result of an assignment in July 2012 by Cheniere Energy Investments, LLC ("CheniereInvestments"), a wholly owned subsidiary of Cheniere Partners, of its rights, title and interest under its TUA. In connection with the assignment, Sabine PassLiquefaction, Cheniere Investments and Sabine Pass LNG entered into a terminal use rights assignment and agreement ("TURA") pursuant to which CheniereInvestments has the right to use Sabine Pass Liquefaction's reserved capacity under the TUA and has the obligation to make the monthly capacity paymentsrequired by the TUA to Sabine Pass LNG. In an effort to monetize Cheniere Investments’ reserved capacity under its TURA during construction of theLiquefaction Project, Cheniere Marketing, LLC ("Cheniere Marketing"), a wholly owned subsidiary of Cheniere, has entered into a variable capacity rightsagreement ("VCRA") pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross40margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. The revenue earned by Sabine Pass LNG fromthe capacity payments made under the TUA and the revenue earned by Cheniere Investments under the VCRA are eliminated upon consolidation of ourfinancial statements. We have guaranteed the obligations of Sabine Pass Liquefaction under its TUA and the obligations of Cheniere Investments under theTURA.In September 2012, Sabine Pass Liquefaction entered into a partial TUA assignment agreement with Total, whereby Sabine Pass Liquefaction willprogressively gain access to Total's capacity and other services provided under Total's TUA with Sabine Pass LNG. This agreement will provide Sabine PassLiquefaction with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Train 5 andTrain 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations ofTrain 3, and permit Sabine Pass Liquefaction to more flexibly manage its LNG storage capacity with the commencement of Train 1. Notwithstanding anyarrangements between Total and Sabine Pass Liquefaction, payments required to be made by Total to Sabine Pass LNG shall continue to be made by Total toSabine 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 FacilitiesThe Liquefaction Project is being developed at the Sabine Pass LNG terminal adjacent to the existing regasification facilities. We plan to construct up tosix 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 thedevelopment 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 proventechnology 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 ispermitted. 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 constructionschedule, we anticipate that Train 1 will produce LNG as early as the end of 2015.CustomersAs 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 quantityof 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 fixedfee of $3.00 per MMBtu. The total expected annual contracted cash flow from BG from the fixed fee component is $723 million. In addition, SabinePass Liquefaction has agreed to make LNG available to BG to the extent that Train 1 becomes commercially operable prior to the beginning of thefirst delivery window. The obligations of BG are guaranteed by BG Energy Holdings Limited, a company organized under the laws of England andWales, 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 firstcommercial 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 guaranteedby Gas Natural SDG S.A., a company organized under the laws of Spain, with a credit rating of Baa2/BBB.41•Korea Gas Corporation ("KOGAS") SPA commences upon the date of first commercial delivery for Train 3 and includes an annual contractquantity 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 of182,500,000 MMBtu of LNG and a fixed fee of $3.00 per MMBtu, equating to expected annual contracted cash flow from fixed fees of $548million. 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 of104,750,000 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 commencementof 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-affiliateparties, for up to a maximum of 104,000,000 MMBtu per annum produced from Train 1 through Train 4. Cheniere Marketing may purchase incrementalLNG 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 byCheniere Marketing, and then 20% of net profits of the remaining 68,000,000 MMBtu sold each year by Cheniere Marketing.ConstructionIn November 2011, Sabine Pass Liquefaction entered into the EPC Contract (Train 1 and 2) with Bechtel. Sabine Pass Liquefaction issued a notice toproceed 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), ifSabine Pass Liquefaction fails to issue notice to proceed to Bechtel by December 31, 2013, then either Sabine Pass Liquefaction or Bechtel may terminate theEPC 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. TheTrains 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 throughDecember 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 $6.0billion, including financing costs and interest expense during construction. The contract price of the EPC Contract (Train 3 and 4) is $3.77 billion, onlysubject 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 theConocoPhillips Petroleum Kenai plant built by Bechtel in 1969 in Kenai, Alaska. Bechtel has since designed and/or constructed LNG facilities using theConocoPhillips Optimized Cascade® technology in Angola, Australia, Egypt, Equatorial Guinea and Trinidad. The design and technology has been proven inover 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 incompletion. 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 throughborrowings, equity contributions from Cheniere Partners and cash flows under our SPAs. We believe that with the net proceeds of borrowings, in addition toconstruction loans and unfunded commitments under the Liquefaction Credit Facility, Sabine Pass Liquefaction will have adequate financial resourcesavailable to complete Train 1 and Train 2 and to meet42its currently anticipated capital, operating and debt service requirements. We currently project that Sabine Pass Liquefaction will generate cash flow fromoperations 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 PassLiquefaction's ongoing capital and operating requirements and to pay the interest on its outstanding debt relating to Train 1 and Train 2.Pipeline FacilitiesCheniere Creole Trail Pipeline, L.P. ("Creole Trail"), an indirect wholly owned subsidiary of Cheniere, owns the Creole Trail Pipeline, a 94-milepipeline 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, andTrunkline 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 twoother 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 TrailPipeline 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 beapproximately $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 $300million, plus any costs incurred by Creole Trail from August 2012 until the purchase date, including, if applicable, any portion of the expected $90 millionfor pipeline modifications.Capital ResourcesSenior Secured NotesWe 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 2016Notes, 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 2020Notes 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 inarrears 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 asecurity interest in all of Sabine Pass LNG's equity interests and substantially all of Sabine Pass LNG's operating assets, and the Sabine Liquefaction Notesare secured on a first-priority basis by a security interest in all of Sabine Pass Liquefaction's equity interests and substantially all of Sabine PassLiquefaction'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 principalplus 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 suchredemption date of the redemption price of the 2016 Notes plus all required interest payments due on the 2016 Notes (excluding accrued but unpaid interest tothe redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points, over (ii) the principalamount 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 theindenture 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 the2020 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 ofredemption. 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 aredemption 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 anamount 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 forsuch equity offering and at least 65% of the aggregate principal amount of the 2020 Notes originally issued remains outstanding after the redemption.43Sabine Pass Liquefaction may redeem some or all of the Sabine Liquefaction Notes at any time prior to November 1, 2020 at a redemption price equalto the "make-whole" price set forth in the indenture governing the Sabine Liquefaction Notes, plus accrued and unpaid interest, if any, to the date ofredemption. 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 aredemption 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 dateof redemption.Under the indentures governing the Sabine Pass LNG Senior Notes, except for permitted tax distributions, Sabine Pass LNG may not makedistributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annualinterest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debtservice reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted under the Sabine Pass LNG Senior Notes only aftersatisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the indentures governing the SabinePass 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 debtservice coverage ratio of 1.25:1.00 is satisfied.Liquefaction Credit FacilityIn 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 tranchessolely 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 scheduleddebt 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 nomore 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 monthsafter 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 ofthe 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 dateor 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 PassLiquefaction is also required to pay commitment fees on the undrawn amount. Sabine Pass Liquefaction is party to interest rate protection agreements withrespect 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 termsreasonably satisfactory to us and the required secured parties. Upon our incurrence of any replacement debt prior to June 30, 2013, including the sale of theSabine Liquefaction Notes, Tranche 4 of the Liquefaction Credit Facility commitments, in an amount equal to the proceeds from such replacement debt lesscertain fees and expenses, will be suspended and extended until December 31, 2013 unless expansion debt shall have been approved prior to such date. Subjectto approval by Sabine Pass Liquefaction's lenders, Sabine Pass Liquefaction currently intends to use such suspended commitments to finance theconstruction 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, 2011and 2010. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, includingaccruals, that are referred to elsewhere in this report. Additional discussion of these items follows the table.44 Year Ended December 31, 2012 2011 2010Sources 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 — 14,249 104,137Total 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 53,349 117,542Cash 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 billionLiquefaction Credit Facility. Sabine Pass Liquefaction made $100.0 million of borrowings under the Liquefaction Credit Facility in August 2012 after meetingthe required conditions precedent to the initial advance. Debt issuance costs primarily relate to $212.8 million paid by Sabine Pass Liquefaction upon theclosing of the Liquefaction Credit Facility.45Proceeds 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 UnitsHolding, 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 generalpartner in connection with the exercise of its right to maintain its 2% ownership interest in us), which were used for general business purposes, includingdevelopment 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 funddevelopment costs associated with the Liquefaction Project. During the year ended December 31, 2011, we sold 0.5 million common units for net cashproceeds of $9.0 million. During the year ended December 31, 2012, we sold 0.5 million common units for net cash proceeds of $11.1 million. We paid $0.3million 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 todevelop 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 CheniereInvestments, effective July 1, 2010, that resulted in the TUA payments being made by Cheniere Investments, our wholly owned subsidiary, instead of beingreceived from Cheniere Marketing. In addition, operating cash flow decreased from 2010 to 2011 as a result of increased development costs in 2011 associatedwith the Liquefaction Project. LNG Terminal and Pipeline Construction-in-Process, netCapital 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 proceedsreceived from the 2020 Notes and from an equity contribution from us.Investment in Restricted Cash and Cash EquivalentsDuring 2012, we invested $343.9 million in restricted cash and cash equivalents. This investment was a result of the $1,458.6 million of restrictedcash 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 theconstruction 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 inthe years ended December 31, 2012, 2011 and 2010, respectively. The decreased amount of distributions to owners from the year ended December 31, 2010 ascompared 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 CheniereMarketing and decreased our available cash in excess of the common unit and general partner distributions. As a result of Cheniere Marketing's assignment ofits TUA to Cheniere Investments, we have not paid distributions on our subordinated units since the distribution made with respect to the quarter endedMarch 31, 2010.46Cash 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 ourpartnership 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. Alldistributions paid to date have been made from accumulated operating surplus. The following provides a summary of distributions paid by us during the yearended December 31, 2012: Total Distribution (in thousands)Date Paid Period Covered by Distribution Distribution Per CommonUnit Common Units Subordinated Units General PartnerUnitsFebruary 14, 2012 October 1, 2011 - December 31, 2011 $0.425 $13,176 $— $269May 15, 2012 January 1, 2012 - March 31, 2012 $0.425 $13,323 $— $272August 15, 2012 April 1, 2012 - June 30, 2012 $0.425 $13,383 $— $273November 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 forour common unitholders and general partner along with certain reserves. Such available cash could be generated through new business development or feesreceived from Cheniere Marketing under the VCRA. The ending of the subordination period and conversion of the subordinated units into common units willdepend 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 theLiquefaction Project. The Class B units are not entitled to cash distributions except in the event of a liquidation (or merger, combination or sale of substantiallyall 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 ofthe 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 holdersof 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 ofrecord 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 contractualobligations in place as of December 31, 2012 (in thousands).47 Payments Due for Years Ended December 31, Total 2013 2014 - 2015 2016 - 2017 ThereafterConstruction and purchase obligations (1) $3,044,606 $1,286,184 $1,532,576 $225,846 $—Long-term debt (excluding interest) (2) 2,185,500 — — 1,665,500 520,000Operating lease obligations (3) (4) 279,777 9,625 19,229 19,039 231,884Service contracts: Affiliate Sabine Pass LNG O&M Agreement (5) 28,176 1,682 3,365 3,365 19,764Affiliate Sabine Pass LNG MSA (5) 112,711 6,729 13,458 13,458 79,066Affiliate Sabine Pass Liquefaction O&MAgreement (5) 62,769 7,828 10,676 7,432 36,833Affiliate Sabine Pass Liquefaction MSA (5) 351,910 31,313 42,704 38,477 239,416Affiliate services agreement (5) 190,366 11,198 22,396 22,396 134,376Cooperative 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 forthe 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 boatsubleases.(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 increasein 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 2of the Liquefaction Project, decreased revenues, increased operating and maintenance expense and increased development expense. Loss on earlyextinguishment of debt increased from zero in 2011 to $42.6 million in 2012 primarily as a result of make-whole payments associated with the earlyrepayments in full of the 2013 Notes. Our general and administrative expense (including affiliate expense) increased $40.2 million, from $26.0 million in 2011to $66.2 million in 2012. This increase in general and administrative expense primarily resulted from increased costs incurred to manage the construction ofTrain 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. Thisdecrease in revenues (including affiliate revenues) primarily resulted from decreased LNG cargo export loading fee revenue, decreased revenues earned underthe 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 toconform to natural gas pipeline specifications. Operating and maintenance expense (including affiliate expense) increased $18.0 million, from $33.7 million in2011 to $51.8 million in 2012. This increase primarily resulted from the loss incurred to purchase LNG to maintain the cryogenic readiness of the SabinePass LNG terminal and increased dredging services in 2012. Development expense (including affiliate expense) increased $3.8 million, from $36.5 million in2011 to $40.2 million in 2012. This increase in development expense resulted from costs incurred to develop the Liquefaction Project.482011 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 decreasein net income primarily resulted from the TUA assignment from Cheniere Marketing to Cheniere Investments, effective July 1, 2010 that resulted in the TUApayments being made by Cheniere Investments, our wholly owned subsidiary, instead of Cheniere Marketing. Beginning July 1, 2010, our affiliate revenuesreflect only tug service revenue and the amount of income earned under the VCRA from Cheniere Marketing because the affiliate revenues earned by SabinePass LNG from Cheniere Investments' capacity payments under the TUA are eliminated upon consolidation of our financial statements. In addition, thedecrease in net income in 2011 was a result of increases in development expenses related to the Liquefaction Project. These decreases in net income werepartially offset by decreased operating and maintenance expenses and decreased development expense in 2011 compared to 2010. Operating and maintenanceexpense (including affiliate expense) decreased $5.5 million, from $39.2 million in 2010 to $33.7 million in 2011. This decrease primarily resulted fromdecreased 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 financialposition 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 theaccounting rules have developed. Accounting rules generally do not involve a selection among alternatives but involve an implementation and interpretation ofexisting rules, and the use of judgment, to apply the accounting rules to the specific set of circumstances existing in our business. In preparing ourconsolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP"), we endeavor to comply with allapplicable 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 foraccounting 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 hasbeen received, (ii) financing for the project is available and (iii) management has committed to commence construction. Prior to meeting these criteria, most ofthe costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and designwork, costs of securing necessary regulatory approvals, and other preliminary investigation and development activities related to our LNG terminals andrelated pipelines. Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs thatare capitalized as property, plant and equipment and certain permits that are capitalized as intangible LNG assets. The costs of lease options are amortizedover 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, capitalizedinterest, as a component of the total cost, will be amortized over the estimated useful life of the asset. 49Revenue Recognition LNG regasification capacity reservation fees are recognized as revenue over the term of the respective TUAs. Advance capacity reservation fees areinitially deferred and amortized over a 10-year period as a reduction of a customer's regasification capacity reservation fees payable under its TUA. Theretained 2% of LNG delivered for each customer's account at the Sabine Pass LNG terminal is recognized as revenues as Sabine Pass LNG performs theservices set forth in each customer's TUA. DerivativesWe use derivative instruments from time to time to hedge the exposure to variability in expected future cash flows attributable to the future sale of ourLNG 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 LNGterminal, and to hedge the exposure to volatility in a portion of the floating-rate interest payments under the Liquefaction Credit Facility. We have disclosedcertain information regarding these derivative positions, including the fair value of our derivative positions, in Note 8—"Financial Instruments" of our Notesto Consolidated Financial Statements.Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivativeinstruments 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 aderivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Werecord changes in the fair value of our derivative positions based on the value for which the derivative instrument could be exchanged between willingparties. To date, all of our derivative positions fair value determinations have been made by management using quoted prices in active markets for similarassets 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 fairvalue 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 inpositions 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 areclassified 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. Changesin fair value of derivative instruments designated as cash flow hedges, to the extent the hedge is effective, are recognized in accumulated other comprehensiveloss on our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive loss into interest expense in ourConsolidated Statements of Operations as the hedged item is recognized. Any change in the fair value resulting from ineffectiveness is recognized immediatelyas derivative gain (loss) on our Consolidated Statements of Operations. We use regression analysis to determine whether we expect a derivative to be highlyeffective as a cash flow hedge prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges have beeneffective. We perform these effectiveness tests prior to designation for all new hedges and on a quarterly basis for all existing hedges. We calculate the actualamount of ineffectiveness on our cash flow hedges using the "dollar offset" method, which compares changes in the expected cash flows of the hedgedtransaction to changes in the value of expected cash flows from the hedge. We discontinue hedge accounting when our effectiveness tests indicate that aderivative 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 orrepaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but continue tohold 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, andaccounts payable approximate fair value because of the short maturity of those instruments. We use available market data and valuation methodologies toestimate the fair value of debt. 50Concentration 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 thesebalances 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. Ourcommodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on adaily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded as an other current asset and not nettedwithin the derivative fair value. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptablecredit 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 thesecounterparties 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 creditrisk by securing TUAs for a significant portion of our regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’srating of AA.Property, Plant and Equipment Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments are capitalized, whileexpenditures for maintenance and repairs and general and administrative activities are charged to expense as incurred. Interest costs incurred on debt obtainedfor the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever isshorter. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plantand 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 thatthe carrying amount of property, plant and equipment might not be recoverable. We have recorded no significant impairments related to property, plant andequipment 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. AtDecember 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 prepareand 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 andlocal 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 thatSabine 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 nostate and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass LNG under this agreement; therefore, Cheniere hasnot 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 prepareand 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 combinedstate and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass Liquefaction will pay to Cheniere an amount equal to the stateand 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 separatecompany basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass51Liquefaction under this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass Liquefaction. The agreement is effective fortax 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 thataffect the amounts reported in the consolidated financial statements and the accompanying notes. Actual results could differ from the estimates andassumptions used.Estimates used in the assessment of impairment of our long-lived assets are the most significant of our estimates. There are numerous uncertaintiesinherent in estimating future cash flows of assets or business segments. The accuracy of any cash flow estimate is a function of judgment used indetermining 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 ourassets. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic andcommodity 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 otherintangible assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historicalexperience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantlyfrom 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 ourconsolidated 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 ofaccounts 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 beingamortized 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 theacquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional ona 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 areasonable 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 carryingamount 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 theSabine 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, withnormal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewaloptions. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualtyexpected, 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 andrelated disclosure requirements. The guidance clarifies the FASB's intent regarding the application of existing fair value measurement and disclosurerequirements, changes the fair value measurement requirements for certain financial instruments, and sets forth additional disclosure requirements for otherfair value measurements. The guidance is to be applied prospectively and is effective for periods beginning after December 15, 2011. We adopted thisguidance effective January 1,522012. The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows, as it only expandeddisclosures.In June 2011, the FASB amended current comprehensive income guidance. The amended guidance eliminates the option to present the components ofother comprehensive income as part of the statement of shareholders’ equity. Instead, we must report comprehensive income in either a single continuousstatement 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 netincome of reclassification adjustments out of AOCI as required in FASB's June 2011 amendment. We adopted this guidance in our first fiscal quarter endingMarch 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 onlyrequired 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 cashinvestments are stated at historical cost, which approximates fair market value on our Consolidated Balance Sheets. Marketing and Trading Commodity Price RiskWe have entered into certain instruments to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNGinventory ("LNG Inventory Derivatives") and to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operatethe Sabine Pass LNG terminal ("Fuel Derivatives"). We use one-day value at risk ("VaR") with a 95% confidence interval and other methodologies for marketrisk measurement and control purposes of our LNG Inventory Derivatives and Fuel Derivatives. The VaR is calculated using the Monte Carlo simulationmethod. The table below provides information about our LNG Inventory Derivatives and Fuel Derivatives that are sensitive to changes in natural gas pricesand interest rates as of December 31, 2012.Hedge Description Hedge Instrument Contract Volume(MMBtu) Price Range ($/MMBtu) Final Hedge MaturityDate Fair Value (inthousands) VaR (in thousands)LNG InventoryDerivatives Fixed price natural gasswaps 1,518,095 $3.366 - $3.893 May 2013 $232 $25Fuel Derivatives Fixed price natural gasswaps 1,095,000 $3.351 - $4.050 January 2014 (98) 5We have entered into interest rate swaps to hedge the exposure to volatility in a portion of the floating-rate interest payments under the LiquefactionCredit 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 ininterest 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 InterestRate Derivatives that are sensitive to changes in the forward 1-month LIBOR curve as of December 31, 2012.Hedge Description Hedge Instrument Initial NotionalAmount Maximum NotionalAmount Fixed Interest RateRange (%) Final HedgeMaturity Date Fair Value (inthousands) 10% Change inLIBOR (inthousands)Interest RateDerivatives Interest rate swaps $20.0 million $2.9 billion 1.978 - 1.981 July 2019 $(26,424) $19,24153ITEM 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.55Reports of Independent Registered Public Accounting Firm—Ernst & Young LLP56Consolidated Balance Sheets58Consolidated Statements of Operations59Consolidated Statements of Comprehensive Loss60Consolidated Statements of Partners’ and Owners’ Capital (Deficit)61Consolidated Statements of Cash Flows62Notes to Consolidated Financial Statements63Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data8854MANAGEMENT’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 ofthe Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework issuedby the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Cheniere Partners' system of internal control over financial reportingis designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes inaccordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financialreporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financialstatement 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 financialreporting 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 Actof 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)55REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe Board of Directors of Cheniere Energy Partners GP, LLC, andUnitholders 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 threeyears in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financialstatements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements andschedule based on our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An auditincludes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing theaccounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe thatour 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 EnergyPartners, 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 yearsin the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statementschedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forththerein.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cheniere EnergyPartners, L.P.'s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issuedby the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 22, 2013 expressed an unqualified opinionthereon./s/ ERNST & YOUNG LLPErnst & Young LLPHouston, TexasFebruary 22, 201356REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors of Cheniere Energy Partners GP, LLC, andUnitholders 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 criteriaestablished 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 itsassessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control OverFinancial 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 standardsrequire that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in allmaterial respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weaknessexists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as weconsidered 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 financialreporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internalcontrol over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately andfairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention ortimely 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 evaluationof effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith 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 asof 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 balancesheets 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, andour report dated February 22, 2013 expressed an unqualified opinion thereon. /s/ ERNST & YOUNG LLPErnst & Young LLPHouston, TexasFebruary 22, 201357CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(in thousands, except unit data) December 31, 2012 2011ASSETS Current assets Cash and cash equivalents $419,292 $81,415Restricted cash and cash equivalents 92,519 13,732Accounts and interest receivable 44 525Accounts receivable—affiliate 2,005 328Advances to affiliate 4,987 692LNG inventory 2,625 473LNG inventory - affiliate 4,420 4,369Prepaid expenses and other 6,652 7,976Total current assets 532,544 109,510 Non-current restricted cash and cash equivalents 272,425 82,394Property, plant and equipment, net 2,704,895 1,514,416Debt issuance costs, net 220,949 17,622Other 17,465 13,358Total assets $3,748,278 $1,737,300LIABILITIES AND PARTNERS’ EQUITY (DEFICIT) Current liabilities Accounts payable $73,760 $704Accounts payable—affiliate 1,122 530Accrued liabilities 47,403 16,751Accrued liabilities—affiliate 5,791 3,794Deferred revenue 26,540 26,629Deferred revenue—affiliate 696 688Other 98 2,722Total current liabilities 155,410 51,818 Long-term debt, net of discount 2,167,113 2,192,418Deferred revenue 21,500 25,500Deferred revenue—affiliate 14,720 12,266Long-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 atDecember 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 $1,737,300See accompanying notes to consolidated financial statements.58CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS(in thousands, except per unit data) Year Ended December 31, 2012 2011 2010Revenues Revenues $256,354 $269,183 $268,328Revenues—affiliate 7,973 14,607 130,954Total revenues 264,327 283,790 399,282 Expenses Operating and maintenance expense 35,457 21,827 27,069Operating and maintenance expense—affiliate 16,300 11,918 12,090Depreciation expense 42,551 42,943 42,299Development expense 37,559 32,448 8,738Development expense—affiliate 2,677 4,025 1,824General and administrative expense 10,303 5,534 6,190General and administrative expense—affiliate 55,940 20,469 20,275Total 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) 461Other 499 196 326Total 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 26,416See accompanying notes to consolidated financial statements.59CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)(in thousands) Year Ended December 31, 2012 2011 2010Net income (loss) $(150,136) $(31,019) $107,568Other 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) $107,568See accompanying notes to consolidated financial statements.60CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF PARTNERS’ ANDOWNERS’ CAPITAL (DEFICIT)(in thousands) CommonUnitholders Class B Unitholders SubordinatedUnitholders General PartnerInterest Accumulated OtherComprehensive Loss Total Partners'Capital (Deficit)Balance, December 31, 2009$(41,494) $— $(427,026) $(11,807) $— $(480,327)Net income17,211 — 88,206 2,151 — 107,568Distributions(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 partnerunits68,701 — — 1,456 — 70,157Distributions(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 partnerunits204,878 — — 45,144 — 250,022Distributions(56,665) — — (1,156) — (57,821)Non-cash contributions— — — 5,663 — 5,663Interest rate cash flow hedges— — — — (27,240) (27,240)Sale of Class B units— 1,887,339 — — — 1,887,339Beneficial conversion feature of ClassB units386,473 (1,950,000) 1,563,527 — — —Amortization of beneficial conversionfeature 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) $1,362,808See accompanying notes to consolidated financial statements.61CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Year Ended December 31, 2012 2011 2010Cash flows from operating activities Net income (loss) $(150,136) $(31,019) $107,568Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation 42,551 42,943 42,299Use 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 4,695Amortization of debt issuance costs 4,362 4,382 4,863Non-cash derivative (gain) loss (619) (195) 124Loss 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 2,874Accounts payable and accrued liabilities 1,960 (1,173) 3,035Accounts payable and accrued liabilities—affiliate 2,412 (1,640) 2,566Deferred revenue—affiliate 8 15 (62,833)Deferred revenue (4,089) (3,964) (3,864)Advances to affiliate (4,764) 2,851 1,815LNG inventory—affiliate (51) (14,969) —Other (1,373) 486 1,621Net 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 53,349 117,542Cash and cash equivalents—end of period $419,292 $81,415 $53,349 See accompanying notes to consolidated financial statements.62CHENIERE 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 ofDecember 31, 2012, Cheniere Energy, Inc. ("Cheniere") owned 59.5% of the limited partnership through its wholly owned subsidiaries, Cheniere LNGHoldings, 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 liquefiednatural gas ("LNG") terminal located on the Sabine Pass deep water shipping channel less than four miles from the Gulf Coast. The Sabine Pass LNGterminal has regasification facilities owned by our wholly owned subsidiary, Sabine Pass LNG, L.P. ("Sabine Pass LNG") that includes existinginfrastructure of five LNG storage tanks with capacity of approximately 16.9 Bcfe, two docks that can accommodate vessels of up to 265,000 cubic metersand vaporizers with regasification capacity of approximately 4.0 Bcf/d. Approximately one-half of the receiving capacity at the Sabine Pass LNG terminal iscontracted 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 regasificationfacilities through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction". We plan to construct up to six Trains (each insequence, "Train 1", "Train 2", "Train 3", "Train 4", "Train 5" and "Train 6"), which are in various stages of development. Each Train has a nominalproduction 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 March26, 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 equityinterests in Sabine Pass LNG-GP, LLC ("Sabine Pass GP") and Sabine Pass LNG-LP, LLC ("Sabine Pass LP"), which own all of the equityinterests 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 partnerinterest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash that we distributein 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 aggregate89.8% 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 administrativeservices for an annual administrative fee of $10.0 million (adjusted for inflation after January 1, 2007), with payment having commencedJanuary 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 havebeen 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 unitsto the public in the Cheniere Partners Offering. Holdings received $164.5 million of net proceeds, after deducting the underwriting discount and structuringfee, upon its sale of 8,445,836 common units. We did not receive any proceeds63CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDfrom 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 PartnersOffering to purchase U.S. Treasury securities that funded a distribution reserve for payment of initial quarterly distributions of $0.425 per common unit, aswell as related quarterly distributions to our general partner, through the quarterly distribution made in respect of the quarter ended June 30, 2009. Ourcommon 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 significantintercompany 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 ouroverall 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 hasbeen received, (ii) financing for the project is available and (iii) management has committed to commence construction. Prior to meeting these criteria, most ofthe costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and designwork, costs of securing necessary regulatory approvals, and other preliminary investigation and development activities related to our LNG terminals andrelated pipelines. Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs thatare capitalized as property, plant and equipment and certain permits that are capitalized as intangible LNG assets. The costs of lease options are amortizedover 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, capitalizedinterest, 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"). Advancecapacity reservation fees are initially deferred and amortized over a 10-year period as a reduction of a customer's regasification capacity reservation feespayable 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 SabinePass LNG performs the services set forth in each customer's TUA.DerivativesWe use derivative instruments from time to time to hedge the exposure to variability in expected future cash flows attributable to the future sale of ourLNG 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 LNGterminal, 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 thefair value amounts of our LNG inventory, fuel and interest rate derivatives, and collateral deposited for such contracts are not netted within the derivative fairvalue. We have disclosed64CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDcertain information regarding these derivative positions, including the fair value of our derivative positions, in Note 8—"Financial Instruments" of our Notesto Consolidated Financial Statements.Accounting guidance for derivative instruments and hedging activities establishes accounting and reporting standards requiring that derivativeinstruments 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 aderivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Werecord changes in the fair value of our derivative positions based on the value for which the derivative instrument could be exchanged between willingparties. To date, all of our derivative positions fair value determinations have been made by management using quoted prices in active markets for similarassets 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 fairvalue 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 inpositions 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 areclassified 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 infair value of derivative instruments designated as cash flow hedges, to the extent the hedge is effective, are recognized in accumulated other comprehensive losson our Consolidated Balance Sheets. We reclassify gains and losses on the hedges from accumulated other comprehensive loss into interest expense in ourConsolidated Statements of Operations as the hedged item is recognized. Any change in the fair value resulting from ineffectiveness is recognized immediatelyas derivative gain (loss) on our Consolidated Statements of Operations. We use regression analysis to determine whether we expect a derivative to be highlyeffective as a cash flow hedge prior to electing hedge accounting and also to determine whether all derivatives designated as cash flow hedges have beeneffective. We perform these effectiveness tests prior to designation for all new hedges and on a quarterly basis for all existing hedges. We calculate the actualamount of ineffectiveness on our cash flow hedges using the "dollar offset" method, which compares changes in the expected cash flows of the hedgedtransaction to changes in the value of expected cash flows from the hedge. We discontinue hedge accounting when our effectiveness tests indicate that aderivative 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 orrepaid; or when we determine that the occurrence of the hedged forecasted transaction is not probable. When we discontinue hedge accounting but continue tohold 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, andaccounts payable approximate fair value because of the short maturity of those instruments. We use available market data and valuation methodologies toestimate 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 thesebalances 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. Ourcommodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on adaily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded as an other current asset and not nettedwithin the derivative fair value. Our interest rate derivative instruments are placed with investment grade financial institutions whom we believe are acceptablecredit 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 thesecounterparties not perform, we may not realize the benefit of some of our derivative instruments.65CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDSabine 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 creditrisk by securing TUAs for a significant portion of our regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’srating of AA.Property, Plant and Equipment Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments are capitalized, whileexpenditures for maintenance and repairs and general and administrative activities are charged to expense as incurred. Interest costs incurred on debt obtainedfor the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever isshorter. We depreciate our property, plant and equipment using the straight-line depreciation method. Upon retirement or other disposition of property, plantand 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 thatthe carrying amount of property, plant and equipment might not be recoverable. We have recorded no significant impairments related to property, plant andequipment 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. AtDecember 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 prepareand 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 andlocal 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 thatSabine 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 nostate and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass LNG under this agreement; therefore, Cheniere hasnot 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 prepareand 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 combinedstate and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass Liquefaction will pay to Cheniere an amount equal to the stateand 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 separatecompany basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass Liquefactionunder this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass Liquefaction. The agreement is effective for tax returns dueon 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 thataffect the amounts reported in the consolidated financial statements and the accompanying notes. Actual results could differ from the estimates andassumptions used.Estimates used in the assessment of impairment of our long-lived assets are the most significant of our estimates. There are numerous uncertaintiesinherent in estimating future cash flows of assets or business segments. The accuracy of any cash flow estimate is a function of judgment used indetermining 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 ourassets. Management reviews its estimates of cash flows on an ongoing66CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDbasis using historical experience and other factors, including the current economic and commodity price environment. Significant negative industry oreconomic trends, including a significant decline in the market price of our common units, reduced estimates of future cash flows for our business ordisruptions to our business could lead to an impairment charge of our long-lived assets, including goodwill and other intangible assets. Our valuationmethodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily onprojections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if ouranalysis 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 aperiod 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 ofaccounts 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 beingamortized 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 theacquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional ona 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 areasonable 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 carryingamount 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 theSabine 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, withnormal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG terminal have terms of up to 90 years including renewaloptions. We have determined that the cost to surrender the Sabine Pass LNG terminal in good order and repair, with normal wear and tear and casualtyexpected, is zero. Therefore, we have not recorded an asset retirement obligation associated with the Sabine Pass LNG terminal.Recent Accounting Standards Not Yet AdoptedWe have also considered all other newly issued accounting guidance that is applicable to our operations and the preparation of our consolidatedfinancial statements, including that which is not yet effective. We do not believe that any such guidance will have a material impact on our consolidatedfinancial 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 ReserveSabine 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 "SeniorNotes." Under the indentures governing the Senior Notes (the "Sabine Pass Indentures"), except for permitted tax distributions, Sabine Pass LNG may notmake distributions until certain conditions are satisfied, including that there must be on deposit in an interest payment account an amount equal to one-sixth ofthe semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment and there must be on67CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDdeposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment. Distributions are permitted only after satisfying theforegoing 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 forthe 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 millionand $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 ReserveIn July 2012, Sabine Pass Liquefaction closed on a $3.6 billion senior secured credit facility (the "Liquefaction Credit Facility"). Under the terms andconditions of the Liquefaction Credit Facility, Sabine Pass Liquefaction is required to deposit all cash received into reserve accounts controlled by a collateraltrustee. Therefore, all of Sabine Pass Liquefaction's cash and cash equivalents are shown as restricted cash and cash equivalents on our Consolidated BalanceSheets. As of December 31, 2012, we classified $100.0 million as non-current restricted cash and cash equivalents held by Sabine Pass Liquefaction as suchfunds 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 heldby 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-currentrestricted 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—AFFILIATELNG inventory and LNG inventory—affiliate are recorded at cost and are subject to lower of cost or market ("LCM") adjustments at the end of eachperiod. LNG inventory—affiliate represents LNG inventory purchased under a related party LNG lease agreement with Cheniere Marketing, LLC ("CheniereMarketing"), a wholly owned subsidiary of Cheniere, as described in Note 13—"Related Party Transactions". LNG inventory cost is determined using theaverage cost method. Recoveries of losses resulting from interim period LCM adjustments are recorded when market price recoveries occur on the sameinventory 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 LCMadjustments 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 endedDecember 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 LNGinventory—affiliate.68CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDNOTE 6—PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consists of LNG terminal costs and fixed assets, as follows (in thousands): December 31, 2012 2011LNG terminal costs LNG terminal $1,641,722 $1,637,724LNG terminal construction-in-process 1,228,647 286LNG site and related costs, net 156 163Accumulated depreciation (166,538) (124,409)Total LNG terminal costs, net 2,703,987 1,513,764 Fixed assets Computer and office equipment 368 227Vehicles 704 416Machinery and equipment 1,473 1,068Other 760 916Accumulated 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 usefullives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 15 and 50 years, asfollows:Components Useful life (yrs)LNG storage tanks 50Marine berth, electrical, facility and roads 35Regasification processing equipment (recondensers, vaporization and vents) 30Sendout pumps 20Others 15-30In June 2012, Train 1 and Train 2 of the Liquefaction Project satisfied the criteria for capitalization. Accordingly, costs associated with theconstruction 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.69CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDNOTE 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 therelated debt. The amortization of debt issuance costs associated with the 2016 Notes and 2020 Notes was recorded as interest expense. The amortization of thedebt issuance costs associated with the Liquefaction Credit Facility for the construction of Train 1 and Train 2 of the Liquefaction Project was capitalized. Asof December 31, 2012, we had capitalized $220.9 million of costs directly associated with the arrangement of debt financing, net of accumulatedamortization, as follows (in thousands): Long-Term Debt Debt Issuance Costs Amortization Period AccumulatedAmortization Net CostsLiquefaction Credit Facility $212,795 7 years $(12,728) $200,0672016 Notes 30,057 10 years (18,030) 12,0272020 Notes 9,092 8 years (237) 8,855Total $251,944 $(30,995) $220,949 NOTE 8—FINANCIAL INSTRUMENTSDerivative InstrumentsWe have entered into certain instruments to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNGinventory ("LNG Inventory Derivatives"), to hedge the exposure to price risk attributable to future purchases of natural gas to be utilized as fuel to operate theSabine Pass LNG terminal ("Fuel Derivatives"), and to hedge the exposure to volatility in a portion of the floating-rate interest payments under the LiquefactionCredit Facility ("Interest Rate Derivatives").The following table (in thousands) shows the fair value of our derivative assets and liabilities that are required to be measured at fair value on arecurring basis as of December 31, 2012 and 2011, which are classified as other current assets, other current liabilities and other non-current liabilities in ourConsolidated Balance Sheets. Fair Value Measurements as of December 31, 2012 December 31, 2011 Quoted Prices inActive Markets(Level 1) Significant OtherObservable Inputs(Level 2) SignificantUnobservable Inputs(Level 3) Total Quoted Prices inActive Markets(Level 1) Significant OtherObservable Inputs(Level 2) Significant UnobservableInputs (Level 3) TotalLNG Inventory Derivatives asset$— $232 $— $232 $— $1,610 $— $1,610Fuel Derivatives liability— 98 — 98 — 1,415 — 1,415Interest 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 currentlybetween willing parties. We value these derivatives using observable commodity price curves and other relevant data. We value our Interest RateDerivatives using valuations based on the initial trade prices. Using an income-based approach, subsequent valuations are based on observable inputs to thevaluation model including interest rate curves, risk adjusted discount rates, credit spreads and other relevant data.70CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDCommodity DerivativesChanges in the fair value of our LNG Inventory Derivatives and Fuel Derivatives are reported in earnings because we have not elected to designate thesederivative instruments as a hedging instrument that is required to qualify for cash flow hedge accounting. The following table (in thousands) shows the fairvalue 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, 2011LNG Inventory Derivatives assetPrepaid expenses and other $232 $1,610Fuel Derivatives liabilityOther current liabilities 98 1,415The following table (in thousands) shows the changes in the fair value and settlements of our LNG Inventory Derivatives recorded in marketing andtrading revenues (losses) on our Consolidated Statements of Operations during the years ended December 31, 2012, 2011 and 2010: Year Ended December 31, 2012 2011 2010LNG Inventory Derivatives gain$1,036 $2,300 $—The following table (in thousands) shows the changes in the fair value and settlements of our Fuel Derivatives recorded in derivative gain (loss) on ourConsolidated Statements of Operations during the years ended December 31, 2012, 2011 and 2010: Year Ended December 31, 2012 2011 2010Fuel Derivatives gain (loss)$(622) $(2,251) $461The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Ourcommodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on adaily margin basis with investment grade financial institutions. Collateral of $0.9 million and $0.8 million deposited for such contracts, which has not beenreflected 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 HedgesIn August 2012, Sabine Pass Liquefaction entered into Interest Rate Derivatives to protect against volatility of future cash flows and hedge a portion ofthe 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 cashflow 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, andreflect changes in fair value through other comprehensive income in our Consolidated Statements of Comprehensive Loss. Any hedge ineffectivenessassociated 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 notcapitalized as part of the Liquefaction Project. The effective portion of the gains or losses on our Interest Rate Derivatives recorded in other comprehensiveincome is reclassified to earnings as interest payments on the Liquefaction Credit Facility impact earnings. In addition, amounts recorded in othercomprehensive income are also reclassified into earnings if it becomes probable that the hedged forecasted transaction will not occur.71CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDThe Interest Rate Derivatives hedge approximately 75% of the weighted average of the expected outstanding borrowings over the term of the LiquefactionCredit Facility. The aggregate notional amount each month follows our expected borrowing schedule under the Liquefaction Credit Facility with an expectedmaximum swap notional amount outstanding of $2.9 billion in 2017. Based on the continued development of our financing strategy for the LiquefactionProject, in particular the fixed-rate debt as described in Note 18—"Subsequent Events", during the fourth quarter of 2012 we determined it was no longerprobable that a portion of the forecasted variable interest payments on the Liquefaction Credit Facility would occur in the time period originally specified. As aresult, 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 ConsolidatedStatements of Operations. We have continued to maintain the Interest Rate Derivatives (both designated and de-designated) in anticipation of our upcomingfinancing needs, particularly for the financing of the construction of Train 3 and Train 4 of the Liquefaction Project, and have concluded that the likelihood ofoccurrence of our variable interest payments has not changed to probable not to occur. As a result, amounts recorded in other comprehensive income related toour designated and de-designated Interest Rate Derivatives will continue to remain in other comprehensive income until interest payments on the LiquefactionCredit Facility impact earnings.At December 31, 2012, Sabine Pass Liquefaction had the following Interest Rate Derivatives outstanding that converted $20.0 million of theLiquefaction 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 avariable interest rate based on the one-month LIBOR. Initial NotionalAmount Maximum NotionalAmount Effective Date Maturity Date Weighted Average FixedInterest Rate Paid Variable Interest RateReceivedInterest Rate Derivatives - Designated $16.1 million $2.3 billion August 14, 2012 July 31, 2019 1.98% One-month LIBORInterest Rate Derivatives - De-designated $3.9 million $575.3 million August 14, 2012 July 31, 2019 1.98% One-month LIBORInterest Rate Derivatives were reflected in our Consolidated Balance Sheets at fair value with the effective portion of the Interest Rate Derivatives' gain orloss recorded in other comprehensive income. Fair value adjustments subsequent to October 1, 2012 on the de-designated portion of the Interest RateDerivatives 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, 2011Interest Rate Derivatives - Designated Non-current derivative liabilities $21,290 $—Interest Rate Derivatives - De-designated Non-current derivative liabilities 5,134 —The following table (in thousands) shows our Interest Rate Derivatives market adjustments recorded during the year ended December 31, 2012: Gain (Loss) in Other Comprehensive Income Gain (Loss) Reclassified from Accumulated OCI intoInterest Expense (Effective Portion) Gain (Loss) Recognized in Income (Ineffective Portionand Amount Excluded from Effectiveness Testing) 2012 2011 2012 2011 2012 2011Interest Rate Derivatives - Designated$(21,290) $— $— $— $— $—Interest Rate Derivatives - De-designated(5,814) — — — — —Interest Rate Derivatives - Settlements(136) — — — — —72CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDThe following table (in thousands) shows the changes in the fair value of our De-designated Interest Rate Derivatives recorded in derivative gain on ourConsolidated Statements of Operations during the years ended December 31, 2012, 2011 and 2010: Year Ended December 31, 2012 2011 2010Interest Rate Derivatives - De-designated$679 $— $—Balance Sheet PresentationThe Company's commodity and interest rate derivatives are presented on a net basis on our Consolidated Balance Sheets as described above. Thefollowing table (in thousands) shows the fair value of our derivatives outstanding on a gross basis: December 31, 2012 December 31, 2011Commodity Derivatives: Assets $607 $1,942Liabilities 474 1,747Interest Rate Derivatives: Assets - designated $17,512 $—Assets - de-designated 4,283 —Liabilities - designated 38,729 —Liabilities - de-designated 9,491 — Other Financial InstrumentsThe estimated fair value of our other financial instruments, including those financial instruments for which the fair value option was not elected are setforth in the table below. The carrying amounts reported on our Consolidated Balance Sheets for cash and cash equivalents, restricted cash and cashequivalents, 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 CarryingAmount EstimatedFair Value CarryingAmount EstimatedFair Value2013 Notes (1) $— $— $550,000 $555,5002016 Notes, net of discount (1) 1,647,113 1,824,177 1,642,418 1,650,6302020 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 onthe 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 ourability to call this debt at anytime without penalty. 73CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDNOTE 9—ACCRUED LIABILITIES As of December 31, 2012 and 2011, accrued liabilities consisted of the following (in thousands): December 31, 2012 2011Interest and related debt fees $16,327 $13,732Affiliate 5,791 3,794LNG liquefaction costs 26,131 1,635LNG terminal costs 977 1,122Other 3,968 262Total accrued liabilities (including affiliate) $53,194 $20,545NOTE 10—DEFERRED REVENUE Advance Capacity Reservation FeeIn 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 additionaladvance capacity reservation fee payment of $10.0 million was paid by Total to Sabine Pass LNG in April 2005. The advance capacity reservation feepayments are being amortized as a reduction of Total’s regasification capacity reservation fee under its TUA over a 10-year period beginning with thecommencement 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 LNGregasification capacity at the Sabine Pass LNG terminal. In December 2005, Chevron exercised its option to increase its reserved capacity by approximately0.3 Bcf/d to approximately 1.0 Bcf/d, making advance capacity reservation fee payments to Sabine Pass LNG totaling $20.0 million. The advance capacityreservation fee payments are being amortized as a reduction of Chevron’s regasification capacity reservation fee under its TUA over a 10-year period beginningwith 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 BalanceSheets, respectively, related to the Total and Chevron advance capacity reservation fees. As of December 31, 2011, we had recorded $4.0 million and $25.5million as current and non-current deferred revenue on our Consolidated Balance Sheets, respectively, related to the Total and Chevron advance capacityreservation fees.TUA PaymentsFollowing the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008, Sabine Pass LNG began receiving capacityreservation fee payments from Cheniere Marketing under its TUA. Effective July 1, 2010, Cheniere Marketing assigned its existing TUA with Sabine PassLNG to Cheniere Investments, including all of its rights, titles, interests, obligations and liabilities in and under the TUA. After the assignment of the TUAfrom Cheniere Marketing to Cheniere Investments, Cheniere Investments began making its TUA payments on a monthly basis. Sabine Pass Liquefactionobtained 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 connectionwith 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 tomake the monthly capacity payments required by the TUA to Sabine Pass LNG. We have guaranteed the obligations of Sabine Pass Liquefaction under itsTUA and the obligations of Cheniere Investments under the TURA. However, the revenue earned by Sabine Pass LNG from Cheniere Investments' capacitypayments under its TUA was eliminated and under its TURA is eliminated upon consolidation of our financial statements. As a74CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDresult, 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 paymentsare 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 andChevron'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 thatallow them to accelerate certain of its property tax payments scheduled to begin in 2019. This ten-year initiative represents an aggregate $25.0 millioncommitment, and will make resources available to the Cameron Parish taxing authorities on an accelerated basis in order to aid in their reconstruction effortsfollowing Hurricane Rita. In exchange for Sabine Pass LNG’s advance payments of ad valorem taxes, Cameron Parish will grant Sabine Pass LNG a dollarfor 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 anagreement with Cheniere Marketing, pursuant to which Cheniere Marketing will advance it any and all amounts payable under the CEAs in exchange for asimilar amount of credits against future ad valorem reimbursements it would owe to Sabine Pass LNG under its TUA starting in 2019. These advance advalorem tax payments were recorded to other assets, and payments from Cheniere Marketing that Sabine Pass LNG utilized to make the early payment of taxeswere 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 andnon-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 2011Long-term debt 2013 Notes $— $550,0002016 Notes 1,665,500 1,665,5002020 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 ThereafterDebt (including related parties): 2016 Notes $1,665,500 $— $— $1,665,500 $—2020 Notes 420,000 — — — 420,000Liquefaction Credit Facility 100,000 — — — 100,000Debt (including related parties) $2,185,500 $— $— $1,665,500 $520,00075CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDSenior NotesIn November 2006, Sabine Pass LNG issued an aggregate principal amount of $2,032.0 million of Senior Secured Notes, consisting of $550.0 millionof 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"). InSeptember 2008, Sabine Pass LNG issued an additional $183.5 million, before discount, of 2016 Notes whose terms were identical to the previouslyoutstanding 2016 Notes. In October 2012, Sabine Pass LNG issued an aggregate principal amount of $420.0 million of 6.50% Senior Secured Notes due in2020 (the "2020 Notes"), whose terms were substantially similar to the outstanding 2016 Notes, and redeemed all of the 2013 Notes. As a result, we recordeda $42.6 million loss on early extinguishment of debt primarily related to make-whole payments. Collectively, the 2013 Notes, 2016 Notes, and 2020 Notes arereferred 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 2020Notes 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 interestin 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 principalplus 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 interestpayments due on the 2016 Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to theTreasury 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 theIndenture, 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 atany 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 certainconditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multipliedby 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 anamount equal to one semi-annual interest payment. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverageratio test of 2:1 and other conditions specified in the indenture. During the years ended December 31, 2012, 2011 and 2010, Sabine Pass LNG madedistributions 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 RightsAgreement"). Under the Registration Rights Agreement, Sabine Pass LNG has agreed to use reasonable efforts to file with the SEC and cause to becomeeffective a registration statement relating to an offer to exchange the notes for an issue of SEC-registered notes with terms substantially identical to the 2020Notes within 360 days after the 2020 Notes were issued. In certain circumstances, Sabine Pass LNG may be required to file a shelf registration statement tocover 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 holdersof the 2020 Notes under certain circumstances.Liquefaction Credit FacilityIn July 2012, Sabine Pass Liquefaction entered into the $3.6 billion Liquefaction Credit Facility with a syndicate of lenders. The Liquefaction CreditFacility 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. TheLiquefaction 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 theLiquefaction 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 million76CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDborrowing 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 baserate, plus the applicable margin. The applicable margin for LIBOR loans is 3.50% during construction and 3.75% during operations, and the applicablemargin 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 LIBORperiod, and interest on base rate loans is due and payable at the end of each calendar quarter. The Liquefaction Credit Facility required Sabine PassLiquefaction to pay certain up-front fees to the agents and lenders in the aggregate amount of approximately $178 million and provides for a commitment feecalculated 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 inquarterly installments, commencing with the first calendar quarter ending at least three months following the completion of Train 1 and Train 2 of theLiquefaction Project. Scheduled repayments are based upon an 18-year amortization, with the remaining balance due upon the maturity of the LiquefactionCredit 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 thatthe Liquefaction Project costs are bona fide expenditures and are permitted under the terms of the Liquefaction Credit Facility. The Liquefaction Credit Facilitydoes not permit Sabine Pass Liquefaction to hold any cash, or cash equivalents, outside of the accounts established under the agreement. Because these cashaccounts 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 onour Consolidated Balance Sheets. The Liquefaction Credit Facility contains customary conditions precedent for the second borrowing and any subsequent borrowings, as well ascustomary affirmative and negative covenants. The obligations of Sabine Pass Liquefaction under the Liquefaction Credit Facility are secured by substantiallyall of the assets of Sabine Pass Liquefaction as well as all of the membership interests in Sabine Pass Liquefaction, and a security interest in ChenierePartners' 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 withrespect to no less than 75% (calculated on a weighted average basis) of the projected outstanding borrowings. In connection with the closing of the LiquefactionCredit Facility, Sabine Pass Liquefaction entered into interest rate swap agreements. The swap agreements have the effect of fixing the LIBOR component of theinterest 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 inpartnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. On May 31, 2007, CheniereLNG 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 tothe 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 thepartnership agreement. Although common and subordinated unitholders are not obligated to fund losses of the partnership, their capital accounts, whichwould 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 minimumdistributions have been achieved and as additional target levels are met. The higher percentages range from 15% up to 50%.77CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDIn 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 funddevelopment 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 ended December 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 yearended 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 UnitsHolding, 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 offeringat 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 itsright 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 rightto maintain its 2% ownership interest in us during the year ended December 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 Bunits") from us in a private placement. In May 2012, Cheniere also entered into a unit purchase agreement with us (the "Cheniere Unit PurchaseAgreeement"). 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 unitpurchase agreements for total consideration of $1.5 billion and $500.0 million, respectively. Proceeds from the financings are being used to fund the equityportion 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 anumber 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 theClass 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% perquarter, subject to an additional upward adjustment for certain equity and debt financings. The Class B units are not entitled to cash distributions except inthe 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 ofthe subordinated units in the event of a liquidation (or merger, combination or sale of substantially all of our assets). The Class B units will mandatorilyconvert 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 withconstruction 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 thefollowing related party transactions:LNG Terminal Capacity AgreementsTerminal Use AgreementIn November 2006, Cheniere Marketing, LLC, a wholly owned subsidiary of Cheniere ("Cheniere Marketing"), reserved approximately 2.0 Bcf/d ofregasification capacity under a firm commitment terminal use agreement ("TUA") with Sabine Pass LNG and was required to make capacity reservation feepayments aggregating approximately $250 million per year for the period from January 1, 2009, through at least September 30, 2028. Cheniere guaranteedCheniere 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 toCheniere Investments, Cheniere Investments began making its TUA payments on a monthly basis. Sabine Pass Liquefaction obtained this reserved capacityas a result of an assignment in July 2012 by Cheniere78CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDInvestments of its rights, title and interest under its TUA. In connection with the assignment, Sabine Pass LNG, Sabine Pass Liquefaction and CheniereInvestments entered into a terminal use rights assignment and agreement ("TURA") pursuant to which Cheniere Investments has the right to use Sabine PassLiquefaction'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, therevenue earned by Sabine Pass LNG from Cheniere Investments' capacity payments under its TUA was eliminated and under its TURA is eliminated uponconsolidation of our financial statements.In connection with monetizing Cheniere Investments’ reserved capacity under its TURA during construction of the Liquefaction Project, CheniereMarketing has entered into a variable capacity rights agreement ("VCRA") pursuant to which Cheniere Marketing is obligated to pay Cheniere Investments80% of the expected gross margin of each cargo of LNG that Cheniere Marketing arranges for delivery to the Sabine Pass LNG terminal. To the extentpayments from Cheniere Marketing to Cheniere Investments under the VCRA increase our available cash in excess of the common unit and general partnerdistributions and certain reserves, the cash would be distributed to Cheniere in the form of distributions on its subordinated units. During the term of theVCRA, 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 ended December 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 willprogressively gain access to Total's capacity and other services provided under Total's TUA with Sabine Pass LNG. This agreement will provide Sabine PassLiquefaction with additional berthing and storage capacity at the Sabine Pass LNG terminal that may be used to accommodate the development of Train 5 andTrain 6, provide increased flexibility in managing LNG cargo loading and unloading activity starting with the commencement of commercial operations ofTrain 3, and permit Sabine Pass Liquefaction to more flexibly manage its storage with the commencement of Train 1. Notwithstanding any arrangementsbetween 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 PassLNG 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 committedto 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. CheniereMarketing 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 themost 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 CheniereMarketing.LNG Lease AgreementIn September 2011, Cheniere Investments entered into an agreement in the form of a lease (the "LNG Lease Agreement")with Cheniere Marketing thatenables Cheniere Investments to supply the Sabine Pass LNG terminal with LNG to maintain proper LNG inventory levels and temperature. The LNG LeaseAgreement also enables Cheniere Investments to hedge the exposure to variability in expected future cash flows of its LNG inventory. Under the terms of theLNG Lease Agreement, Cheniere Marketing funds all activities related to the purchase and hedging of the LNG, and Cheniere Investments reimbursesCheniere 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 CheniereMarketing 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 oflosses resulting from interim period LCM adjustments are made due to market price recoveries on the same LNG inventory—affiliate in the same fiscal yearand 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 1,369,000MMBtu 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 MMBtuof LNG inventory—affiliate recorded at $4.4 million on our79CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDConsolidated Balance Sheets. During the years ended December 31, 2012 and 2011, we recognized a loss of $1.4 million and $11.4 million, respectively, as aresult 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 tothe 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 thesederivative instruments are classified as revenues on our Consolidated Statements of Operations. We recorded revenues of $1.0 million and $2.3 million relatedto LNG inventory—affiliate derivatives in the years ended December 31, 2012 and 2011, respectively.Service AgreementsDuring the years ended December 31, 2012, 2011 and 2010, we recorded general and administrative expense—affiliate of $53.5 million, $19.0 millionand $15.9 million, respectively, under the following service agreements.Cheniere Partners Services AgreementWe 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 theprovision of various general and administrative services for our benefit. In addition, we reimburse Cheniere Terminals for all audit, tax, legal and finance feesincurred by Cheniere Terminals that are necessary to perform the services under the agreement.Sabine Pass LNG O&M AgreementSabine Pass LNG has entered into a long-term operation and maintenance agreement (the "Sabine Pass LNG O&M Agreement") with a wholly ownedsubsidiary of Cheniere pursuant to which we receive all necessary services required to operate and maintain the Sabine Pass LNG receiving terminal. SabinePass 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 to50% of the salary component of labor costs in certain circumstances to be agreed upon between Sabine Pass LNG and the counterparty at the beginning ofeach operating year. In addition, Sabine Pass LNG is required to reimburse the counterparty for its operating expenses, which consist primarily of laborexpenses. Sabine Pass LNG MSASabine Pass LNG has entered into a long-term management services agreement (the "Sabine Pass LNG MSA") with Cheniere Terminals, pursuant towhich 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 AgreementIn May 2012, Sabine Pass Liquefaction entered into an operation and maintenance agreement (the "Liquefaction O&M Agreement") with a whollyowned subsidiary of Cheniere and our general partner pursuant to which we receive all of the necessary services required to construct, operate and maintain theliquefaction facilities. Before the liquefaction facilities are operational, the services to be provided include, among other services, obtaining governmentalapprovals on behalf of Sabine Pass Liquefaction, preparing an operating plan for certain periods, obtaining insurance, preparing staffing plans and preparingstatus reports. After the liquefaction facilities are operational, the services include all necessary services required to operate and maintain the liquefactionfacilities.Before the liquefaction facilities are operational, in addition to reimbursement of operating expenses, Sabine Pass Liquefaction is required to pay amonthly fee equal to 0.6% of the capital expenditures incurred in the previous month. After substantial completion of each Train, for services performed whilethe liquefaction facilities are operational, Sabine Pass80CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDLiquefaction will pay in addition to the reimbursement of operating expenses, a fixed monthly fee of $83,333 (indexed for inflation) for services with respect tosuch Train.Sabine Pass Liquefaction MSAIn May 2012, Sabine Pass Liquefaction entered into a management services agreement (the "Liquefaction MSA") with a wholly owned subsidiary ofCheniere pursuant to which such subsidiary was appointed to manage the construction and operation of the liquefaction facilities, excluding those mattersprovided for under the Liquefaction O&M Agreement. The services to be provided include, among other services, exercising the day-to-day management ofSabine Pass Liquefaction's affairs and business, managing Sabine Pass Liquefaction's regulatory matters, managing bank and brokerage accounts andfinancial books and records of Sabine Pass Liquefaction's business and operations, and providing contract administration services for all contracts associatedwith the liquefaction facilities. Sabine Pass Liquefaction will pay a monthly fee equal to 2.4% of the capital expenditures incurred in the previous month. Aftersubstantial 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 thatallow 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 theirreconstruction efforts following Hurricane Rita. In exchange for Sabine Pass LNG's payments of annual ad valorem taxes, Cameron Parish will grant SabinePass 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 TUArevenues 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 SabinePass LNG under its TUA starting in 2019. In June 2010, Cheniere Marketing assigned its existing TUA to Cheniere Investments and concurrently enteredinto a VCRA, allowing Cheniere Marketing to monetize Cheniere Investments' capacity under the TUA after the assignment. In July 2012, CheniereInvestments entered into an amended and restated VCRA with Cheniere Marketing in order for Cheniere Investments to monetize the capacity rights grantedunder the TURA during construction of the Liquefaction Project. The amended and restated VCRA provides that Cheniere Marketing will continue to fund theCEAs 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 tomake 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 othernon-current assets and non-current deferred revenue resulting from Sabine Pass LNG's ad valorem tax payments and the advance TUA payments receivedfrom 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 PassLNG 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 thenatural 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 tothe 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 thisagreement in the years ended December 31, 2012, 2011 and 2010, respectively. Sabine Pass LNG recorded $2.8 million, zero and zero of natural gas sold toCheniere Marketing under this agreement in the year ended the December 31, 2012, 2011 and 2010, respectively.81CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDLNG Terminal Export AgreementIn January 2010, Sabine Pass LNG and Cheniere Marketing entered into an LNG Terminal Export Agreement that provides Cheniere Marketing theability 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 millionpursuant to this agreement in the years ended December 31, 2012, 2011 and 2010, respectively.Tug Boat Lease Sharing AgreementIn connection with its tug boat lease, Sabine Pass Tug Services, LLC, a wholly owned subsidiary of Sabine Pass LNG ("Tug Services"), entered intoa tug sharing agreement with Cheniere Marketing to provide its LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG terminal. TugServices 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—LEASESDuring 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 underthe land leases and tug boat lease described below (in thousands):Year ending December 31, Lease Payments (2)2013 $9,6252014 9,6252015 9,6042016 9,5772017 9,462Later years (1) 231,884Total 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 ofsublease payments Sabine Pass LNG will receive from its three TUA customers that effectively offset these lease payment obligations, as discussedbelow. Land LeasesIn January 2005, Sabine Pass LNG exercised its options and entered into three land leases for the site of the Sabine Pass LNG terminal. The leaseshave an initial term of 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. In February 2005, two of the three leaseswere 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 LNGentered into an additional land lease, thereby increasing the total acreage under lease to 883 acres. The annual lease payments are adjusted for inflation every 5years 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 theLiquefaction Project. The annual lease payment is $138,000. The lease has an initial term of five years, with options to renew for five 1-year extensions withsimilar 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 LiquefactionProject. The annual lease payment is $257,800. The lease has an initial term of 30 years, with options to renew for six 10-year extensions with similar termsas 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.82CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDWe 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 LeaseIn 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 aresult 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 anoption 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 theTug Agreement. In addition, we have concluded that the tug lease contained in the Tug Agreement is an operating lease, and as such, the equipment componentof 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 providetheir LNG cargo vessels with tug boat and marine services at our LNG terminal and effectively offset the cost of our lease. The Tug Sharing Agreementprovides 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 andregasification 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 toadjustment 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 placinginto 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 LNGterminal. 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 toadjustment 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 toproceed 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 PassLiquefaction fails to issue the notice to proceed by December 31, 2013, then either party may terminate the EPC Contract, and Bechtel will be paid costsreasonably 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. 83CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDPublic 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 willinclude costs related to compliance with the Sarbanes-Oxley Act of 2002, filing annual and quarterly reports with the SEC, increased audit fees, taxcompliance and publicly traded partnership tax reporting, investor relations, director compensation, directors’ and officers’ insurance, legal fees, registrar andtransfer agent fees and stock exchange fees. Cheniere advanced us funds to pay public company expenses associated with being a publicly traded partnershipthrough 2008, after which time we used available cash to pay such expenses directly and, after payment of the initial quarterly distribution on all units, toreimburse 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 assignsto 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 coveredLNG facilities, subject to a minimum of $2.0 million and a maximum of approximately $11.0 million per production year. In 2003, Freeport LNGcontractually assumed the obligation to pay the Crest Royalty for natural gas processed at Freeport LNG's receiving terminal. Subsequently, the calculation ofthe Crest Royalty and the scope of Freeport LNG's assumed obligation to pay the Crest Royalty became the subject of litigation involving Cheniere, CrestEnergy, 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 CrestEnergy's dismissal from the Crest Royalty Litigation. In September 2012, Cheniere entered into a settlement of the remaining claims in the Crest RoyaltyLitigation with Freeport LNG. As part of the settlement agreement, Cheniere terminated the Crest Royalty. As a result of all of these transactions, Cheniereresolved 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 holdersof 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 prepareand 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 andlocal 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 thatSabine 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 nostate and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass LNG under this agreement; therefore, Cheniere hasnot 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 prepareand 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 combinedstate and local tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass Liquefaction will pay to Cheniere an amount equal to the stateand 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 separatecompany basis. There have been no state and local taxes paid by Cheniere for which Cheniere could have demanded payment from Sabine Pass Liquefactionunder this agreement; therefore, Cheniere has not demanded any such payments from Sabine Pass Liquefaction. The agreement is effective for tax returns dueon or after August 2012. 84CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDCooperative Endeavor Agreements ("CEAs") In July 2007, Sabine Pass LNG executed CEAs with various Cameron Parish, Louisiana taxing authorities. See Note 13—"Related PartyTransactions" 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 analyzecurrent information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, asof December 31, 2012, there were no threatened or pending legal matters that would have a material impact on our consolidated results of operations, financialposition 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 2010Cash paid during the year for interest, net of amounts capitalized $160,273 $164,513 $164,793LNG terminal costs funded with accounts payable and accrued liabilities 99,680 — —NOTE 17—Cash Distributions and Net Income (Loss) per Common UnitCash DistributionsOur partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in ourpartnership 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 generalpartner. All distributions paid to date have been made from operating surplus as defined in the partnership agreement. The following provides a summary ofdistributions paid by us during the years ended December 31, 2012, 2011 and 2010: Total Distribution (in thousands)Date Paid Period Covered by Distribution Distribution PerCommon Unit Distribution PerSubordinated Unit Common Units Class B Units Subordinated Units General PartnerUnitsNovember 14, 2012 July 1 - September 30, 2012 $0.425 $— $16,783 — — $342August 13, 2012 April 1 - June 30, 2012 0.425 — 13,383 — — 273May 14, 2012 January 1 - March 31, 2012 0.425 13,323 — 272February 12, 2012 October 1 - December 31, 2011 0.425 13,176 — 269November 14, 2011 July 1 - September 30, 2011 0.425 — 13,176 — — 269August 12, 2011 April 1 - June 30, 2011 0.425 — 11,446 — — 234May 13, 2011 January 1 - March 31, 2011 0.425 — 11,335 — — 231February 11, 2011 October 1 - December 31, 2010 0.425 — 11,229 — — 229November 12, 2010 July 1 - September 30, 2010 0.425 — 11,227 — — 229August 13, 2010 April 1 - June 30, 2010 0.425 — 11,227 — — 229May 14, 2010 January 1 - March 31, 2010 0.425 0.425 11,227 — 57,538 1,403February 12, 2010 October 1 - December 31, 2009 0.425 0.425 11,227 — 57,538 1,403The subordinated units will receive distributions only to the extent we have available cash above the minimum quarterly distribution requirement forour 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 thedistribution made with respect to the quarter ended March 31, 2010.85CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDPursuant 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 Bunit 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 marketprice of the common units into which they are convertible. This discount totaling $1,950.0 million represents a beneficial conversion feature and is reflectedas 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 atissuance on our consolidated statement of partners’ and owners' capital (deficit). The beneficial conversion feature is considered a dividend that will bedistributed ratably with respect to any Class B unit from its issuance date through its conversion date, resulting in an increase in Class B unitholders' capitaland a decrease in common and subordinated unitholders’ capital. The impact of the beneficial conversion feature is also included in earnings per unit for theyear ended December 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 anallocation of undistributed net income (loss) based on provisions of the partnership agreement, divided by the weighted average number of common unitsoutstanding. 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 respectto that period and that any residual amount representing undistributed net income be allocated to common unitholders and other participating unitholders to theextent 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 apro rata basis based on provisions of the partnership agreement. Distributions are treated as distributed earnings in the computation of earnings per commonunit 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 cashdistributions actually declared, thereby excluding the IDRs from participating in undistributed net income (loss). We did not allocate earnings or losses to IDRholders for the purpose of the two class method earnings per unit calculation for any of the periods presented.86CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUEDThe following table provides a reconciliation of net income (loss) and the allocation of net income (loss) to the common units and the subordinated unitsfor 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 PartnerYear Ended December 31, 2012 Net loss $(150,136) Declared distributions 61,501 60,271 — — 1,230Amortization 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 — — 1,002Assumed 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 2,090Assumed allocation of undistributed net loss 3,030 — — 2,969 61Assumed 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 EVENTSSabine Liquefaction NotesIn 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 Train1 and Train 2 of the Liquefaction Project in lieu of a portion of the commitments under the Liquefaction Credit Facility.87SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTSSUMMARIZED QUARTERLY FINANCIAL DATA(unaudited)Quarterly Financial Data—(in thousands, except per unit amounts) FirstQuarter SecondQuarter ThirdQuarter FourthQuarterYear ended December 31, 2012: Revenues $69,323 $61,396 $66,308 67,300Income from operations 24,891 18,275 772 19,602Net 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 $70,824Income from operations 41,127 36,932 29,523 37,044Net 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 unitoutstanding for basic and diluted shares outstanding for each quarter and the full year are performed independently.88ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIALDISCLOSURE 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 byus 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 rulesand forms, and that such information is accumulated and communicated to our management, including our general partner's principal executive officer andprincipal 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 principalfinancial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) areeffective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (i) accumulated and communicated toour management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding requireddisclosure 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 arereasonably 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 isincorporated herein by reference. ITEM 9B. OTHER INFORMATIONSabine Pass LNG NotesOn October 16, 2012, Sabine Pass LNG, L.P. ("Sabine Pass LNG"), our wholly owned subsidiary, closed the sale of $420 million aggregateprincipal amount of its 6.5% Senior Secured Notes due 2020 (the "2020 Notes") pursuant to the Purchase Agreement dated October 1, 2012 by and amongSabine 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 Noteswere sold on a private placement basis in reliance on Section 4(2) of the Securities Act and Rule 144A and Regulation S thereunder.IndentureThe 2020 Notes were issued pursuant to the Indenture, dated as of October 16, 2012 (the "Indenture"), by and among Sabine Pass LNG, theguarantors 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 Noteswill 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 "issuedate"), 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 aresenior 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 issubordinated 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 seniorand 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 thatis 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 ofSabine 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 isstructurally subordinated to all indebtedness and other liabilities of Sabine Pass LNG's subsidiaries that do not provide guarantees with respect to the 2020Notes.89As 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 restrictedsubsidiaries that guarantee other indebtedness of Sabine Pass LNG, subject to certain exceptions. Such guarantees will be joint and several obligations of theguarantors 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 pricesspecified 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 ofthe 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 dateof 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 amountof 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 theredemption 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 ofclosing such equity offering and at least 65% of the aggregate principal amount of the 2020 Notes issued under the Indenture on the issue date remainsoutstanding after the redemption.The Indenture also contains customary terms, events of default and covenants relating to, among other things, incurring additional indebtedness orissuing 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 orother payments by Sabine Pass LNG's restricted subsidiaries, incurring liens, entering into transactions with affiliates, consolidating, merging, selling orleasing all or substantially all of Sabine Pass LNG's assets and entering into sale and leaseback transactions. In addition, Sabine Pass LNG will be requiredto 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 SecuredNotes 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 ofeach 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 PassLNG's Current Report on Form 8-K filed on October 19, 2012, and is incorporated by reference herein.Registration Rights AgreementIn 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 anyfuture guarantors of the 2020 Notes will agree, to use commercially reasonable efforts to file with the U.S. Securities and Exchange Commission and cause tobecome effective a registration statement with respect to an offer to exchange the 2020 Notes for a like aggregate principal amount of debt securities of SabinePass 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 anyincrease in annual interest rate) that are registered under the Securities Act. Sabine Pass LNG has agreed, and any future guarantors of the 2020 Notes willagree, to use commercially reasonable efforts to cause such registration statement to become effective within 360 days after the issue date. Under specifiedcircumstances, Sabine Pass LNG has also agreed, and any future guarantors will also agree, to use commercially reasonable efforts to cause to becomeeffective 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 complywith 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 isfiled 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 KOGASOn February 18, 2013, Sabine Pass Liquefaction and KOGAS entered into Amendment No. 1 of LNG Sale and Purchase Agreement. AmendmentNo. 1 amends the SPA entered into on January 30, 2012 between Sabine Pass Liquefaction and KOGAS to provide, among other things, that Sabine PassLiquefaction 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 theconditions 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). In90addition, 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 GAILOn 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 PassLiquefaction 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 theconditions 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, receivingregulatory approvals, securing necessary financing arrangements and making a final investment decision to construct Train 4 be satisfied or waived on orprior to December 31, 2013, rather than June 30, 2013.PART IIIITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF OUR GENERAL PARTNER AND CORPORATEGOVERNANCE 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 byour 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 generalpartner. 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 andVincent Pagano, Jr., each of whom is an independent director and satisfies the additional independence and other requirements for audit committee membersprovided 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 thatLon McCain and Oliver G. Richard, III meet the qualifications of a "financial expert" and are "financially sophisticated" as such terms are defined by theSEC 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 compliancewith legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to retain and terminate ourindependent registered public accounting firm, approve all audit services and related fees and the terms thereof, and pre-approve any non-audit services to berendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of ourindependent 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 independentdirectors, Vincent Pagano, Jr., chairman, Lon McCain, Oliver G. Richard, III and James Robert Ball, to review specific matters that the board believes mayinvolve 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 theconflicts committee may not be security holders, officers or employees of our general partner, directors, officers, or employees of affiliates of the generalpartner or holders of any ownership interest in us other than common units or other publicly traded units and must meet the independence standardsestablished by the NYSE MKT, the Exchange Act and other federal securities laws. Any matter approved by the conflicts committee is conclusively deemed tobe 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.91 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 ourunitholders 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 orindirectly 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. Ourgeneral partner has paid no cash compensation to its executive officers since its inception. All of the executive officers of our general partner are also executiveofficers of Cheniere. Cheniere compensates these officers for the performance of their duties as executive officers of Cheniere, which includes managing ourpartnership. 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 February15, 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 adirector 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 adirector of the general partner since 2008. Messrs. Ball, Foley, Klimczak, Pagano, Richard and Thames were elected as directors of the general partner in2012.Name Age Position with Our General PartnerCharif Souki 60 Director, Chairman of the Board and Chief Executive OfficerR. Keith Teague 48 Director, President and Chief Operating OfficerMeg A. Gentle 38 Director, Senior Vice President and Chief Financial OfficerLon McCain 65 DirectorJames R. Ball 62 DirectorDavid I. Foley 45 DirectorSean T. Klimczak 36 DirectorVincent Pagano, Jr. 62 DirectorOliver G. Richard, III 60 DirectorH. 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 January2007. Mr. Souki, a co-founder of Cheniere, is Chairman of Cheniere's board of directors and Chief Executive Officer and President of Cheniere. SinceDecember 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 investmentbanker. 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 July1996 until September 1997. Mr. Souki has over 20 years of independent investment banking experience in the oil and gas industry and has specialized inproviding financing for small capitalization companies with an emphasis on the oil and gas industry. Mr. Souki received a B.A. from Colgate University andan 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 wasdetermined 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 generalpartner of Sabine Pass LNG, L.P. and is responsible for developing the companies' overall strategy and vision and implementing the business plans. Inaddition, with twenty years of experience as an investment banker specializing in the oil and gas industry, Mr. Souki brings a unique perspective to the boardof 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. Hehas served as Senior Vice President-Asset Group of Cheniere since April 2008. Prior to that time, he served as Vice President-Pipeline Operations of Chenierebeginning 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 ofStrategic Planning for the CMS Panhandle Companies from December 2001 until September 2003. Mr. Teague is also President of the general partner92of 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 anyother 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 March2009. 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 FinancialOfficer of Cheniere since March 2009. She served as Senior Vice President - Strategic Planning and Finance from February 2008 to March 2009. Prior to thattime, 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 developmentand strategic planning for Anadarko Petroleum Corporation, an oil and gas exploration and production company, for six years and energy market analysis forPace Global Energy Services, an energy management and consulting firm, for two years. Ms. Gentle received her B.A. in economics and international affairsfrom 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 theenergy industry and because of the perspective she brings as the Chief Financial Officer of Cheniere, Cheniere GP and the general partner of Sabine PassLNG, 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 GasStrategies Group Ltd, a professional services company providing commercial energy advisory services (“GSG”), since September 2011. From 1988 untilAugust 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 andequities 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. ineconomics from the University of Colorado and a Master of Science from City University Business School (now Cass Business School). Mr. Ball has notheld 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 hisbackground as an advisor in the energy industry.David I. Foley is 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 anemployee of AEA Investors Inc., a private equity investment firm, from 1991 to 1993 and a consultant with The Monitor Company, a business managementconsulting 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 aMaster of Arts in economics from Northwestern University and a Master of Business Administration from Harvard Business School. It was determined thatMr. Foley should serve as a director of our general partner because of his financial expertise and his experience in the energy industry.Sean T. Klimczak is 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 equityinvestment firm, from 2001 to 2003 and an employee in the Mergers & Acquisitions department of the Investment Banking division of Morgan Stanley, afinancial 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 BusinessAdministration 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 wasExecutive Vice President and Chief Financial Officer of Ellora Energy Inc., a private, independent exploration and production company from July 2009 toAugust 2010. Prior to that, he was Vice President, Treasurer and Chief Financial Officer of Westport Resources Corporation, a publicly traded exploration andproduction company, from 2001 until the sale of that company to Kerr-McGee Corporation in 2004. From 1992 until joining Westport, Mr. McCain wasSenior Vice President and Principal of Petrie Parkman & Co., an investment banking firm specializing in the oil and gas industry. From 1978 until joiningPetrie Parkman, Mr. McCain held senior financial management positions with Presidio Oil Company, Petro-Lewis Corporation and Ceres Capital. He iscurrently on the board of directors of Crimson Exploration, Inc., a publicly traded oil and natural gas exploration and production company, and ContinentalResources, Inc., a publicly traded oil and natural gas exploration and93production company. During the past five years, he served as a director of Transzap, Inc., a privately held provider of digital data and electronic paymentsolutions. 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 adirector of our general partner because of his experience as a chief financial officer for energy companies and his background as an investment banker in theenergy 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 publiccompany advisory matters from 1981 until his retirement at the end of 2012. Mr. Pagano earned his law degree, cum laude, from Harvard Law School andhis B.S. in Engineering, summa cum laude, from Lehigh University and an M.S. in Engineering from the University of California Berkley. Mr. Pagano hasnot 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 ofhis capital markets expertise and his experience as an advisor to public companies on a variety of corporate matters.Oliver G. Richard, III is a director of our general partner and serves as a member of the Audit Committee and Conflicts Committee. Mr. Richard hasserved as Chairman of Cleanfuel USA, an alternative vehicular fuel company, since September 2007 and, for the past five years, he has been the owner andpresident of Empire of the Seed LLC, a private consulting firm in the energy and management industries. Mr. Richard served as Chairman, President andChief Executive Officer of Columbia Energy Group, a natural gas company, from 1995 until 2000. Mr. Richard was a Commissioner on the Federal EnergyRegulatory 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. Itwas determined that Mr. Richard should serve as a director of our general partner because of his extensive background in the energy industry, including hisexperience in both the public and private sectors of the energy industry.H. Davis Thames is a director of our general partner. Mr. Thames has served as Senior Vice President, Marketing since December 2007 and Presidentof 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 VicePresident Marketing & Analysis in July 2005, Mr. Thames worked for Cross Country Energy, LLC, from 2003 to 2005, Enron Corp from 2003 to 2005 andFlowserve 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 MechanicalEngineering from Texas A&M University, and an M.B.A. from the UCLA Anderson School of Management. Mr. Thames has not held any other directorshippositions 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 hisexperience 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 ofhonesty, loyalty, fairness and forthrightness. The Code of Business Conduct and Ethics was approved by the directors of our general partner. Our Code ofBusiness Conduct and Ethics is posted at www.cheniereenergypartners.com. We also intend to post any changes to or waivers of our Code of BusinessConduct 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 registeredclass of our equity securities to file initial reports of ownership and reports of changes in ownership with the SEC. Such persons are required by SECregulation 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 writtenrepresentations from the directors and executive officers of our general partner, we believe that all Section 16(a) filing requirements were met during 2012 in atimely manner. 94ITEM 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 alsoexecutive officers of Cheniere. Cheniere compensates these officers for the performance of their duties as executive officers of Cheniere, which includesmanaging our partnership. Cheniere does not allocate this compensation between services for us and services for Cheniere and its affiliates. Instead, an affiliateof Cheniere provides us various general and administrative services, such as technical, commercial, regulatory, financial, accounting, treasury, tax and legalstaffing and related support services, pursuant to a services agreement for which we pay a non-accountable overhead reimbursement charge of $2.8 million perquarter (indexed for inflation). For a description of the services agreement, see Note 13—"Related Party Transactions" of our Notes to Consolidated FinancialStatements.In 2007, the board of directors of our general partner adopted the Cheniere Energy Partners, L.P. Long-Term Incentive Plan for employees, consultantsand directors of our general partner, employees of its affiliates and consultants to its subsidiaries. The purpose of the plan is to enhance attraction andretention of qualified individuals who are essential for the successful operation of our partnership and to encourage them to align their interests with ourinterests through an equity ownership stake in us. The plan allows for the grant of options, restricted units, phantom units and unit appreciation rights. Up to1,250,000 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 ofour 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 ofdirectors of our general partner, acting in lieu of a compensation committee, has reviewed and discussed the Compensation Discussion and Analysis withmanagement. Based on this review and discussion, the board of directors of our general partner recommended that the Compensation Discussion and Analysisbe included in this annual report on Form 10-K. By the members of the board of directors of our general partner: Charif SoukiR. Keith TeagueMeg A. GentleJames R. BallDavid I. FoleySean T. KlimczakLon McCainVincent Pagano, Jr.Oliver G. Richard, IIIH. 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 ourgeneral partners' officers, the compensation would be reviewed and approved by the entire board of directors of our general partner because they perform thefunctions of a compensation committee in the event such committee is needed. None of the directors or executive officers of our general partner served as amember 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 generalpartner 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 generalpartner 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 auditcommittee 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 theboard and are payable quarterly. In addition to the95annual fees paid to the non-management directors, commencing February 1, 2012 and ending May 31, 2012, the Chairman of the Conflicts Committeereceived 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 withincreased work performed by the Conflicts Committee in connection with the Liquefaction Project during that time. The special monthly fees were paid inarrears. 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-TermIncentive 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 anadditional 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 ofthe 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 fairmarket value of a common unit on such date. The directors receive no distributions, and no distributions accrue, on the outstanding phantom units.Indemnification of DirectorsWe have entered into indemnification agreements with each of our directors, which provide for indemnification with respect to all expenses and claimsthat 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 orfiduciary of Cheniere GP or any of our subsidiaries. Pursuant to the agreements, no indemnification will generally be provided (1) for claims brought by thedirector, except for a claim of indemnity under the indemnification agreement, if we approve the bringing of such claim, or if the Delaware Limited LiabilityCompany Act requires providing indemnification because our director has been successful on the merits of such claim, (2) for claims under Section 16(b) ofthe 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 willfulmisconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. Indemnification will be provided to the extent permittedby 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 expandedafter 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 theindemnification agreements.The following table shows the compensation of the board of directors of our general partner for the 2012 fiscal year:Name FeesEarnedor Paidin Cash UnitAwards (1) OptionAwards Non-EquityIncentive PlanCompensation Change in PensionValue andNonqualifiedDeferredCompensationEarnings All OtherCompensation TotalCharif Souki (2) $— $— $— $— $— $— $—R. Keith Teague(2) — — — — — — —Meg A. Gentle (2) — — — — — — —James R. Ball (3) 9,722 305,280 — — — — 315,002Mike Bock (4) 122,304 62,700 — — — — 185,004David I. Foley (5) — — — — — — —Sean T. Klimczak (5) — — — — — — —Lon McCain (6) 133,332 70,320 — — — — 203,652Vincent Pagano, Jr. (7) — 249,000 — — — — 249,000Oliver G. Richard, III (8) 12,639 305,280 — — — — 317,919Robert J. Sutcliffe (9) 123,640 70,320 — — — — 193,960H. Davis Thames (2) — — — — — — —Don A. Turkleson (10) 40,694 62,700 — — — — 103,394Walter 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 ofgrant and are revalued on a quarterly basis through the date of vesting.96(2)Charif Souki, Keith Teague and Meg Gentle are executive officers of our general partner and are also executive officers of Cheniere. Davis Thames isan executive officer of Cheniere. Cheniere compensates these officers for the performance of their duties as executive officers of Cheniere, whichincludes 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 onthat 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 of4,500 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.Pand 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 thevesting 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 $249,000on 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 $305,280on 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 thevesting 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 onSeptember 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 vestingschedule.(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 thevesting 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 onSeptember 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 vestingschedule.(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 directoreffective 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 normalvesting schedule. Mr. Williams also had use of an office, parking space, laptop and blackberry at Cheniere's headquarters during 2012. The prorata amount of office lease expense related to that space was approximately $3,348. The parking expense was approximately $3,442 and the laptopand blackberry expense was approximately $5,004.ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT, ANDRELATED UNITHOLDER MATTERS The limited partner interest in our partnership is divided into units. As of February 13, 2013, the following units were outstanding: 39,488,488common 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 beneficialownership 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 beneficialownership 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 thedisposition of such security. A person is also deemed97to 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 oneperson 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 economicinterest. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown asbeneficially owned by them, subject to community property laws where applicable. Except as indicated by footnote, the address for the beneficial owners listedbelow is 700 Milam Street, Suite 800, Houston, Texas 77002.Name of Beneficial Owner CommonUnitsBeneficiallyOwned PercentageofCommonUnitsBeneficiallyOwned Class B UnitsBeneficially Owned Percentage ofClass B UnitsBeneficiallyOwned SubordinatedUnitsBeneficiallyOwned PercentageofSubordinatedUnitsBeneficiallyOwned Percentageof TotalEquitySecuritiesBeneficiallyOwnedCheniere 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 CommonUnits Holding, LLC and Cheniere Class B Units Holding, LLC and and may, therefore, be deemed to beneficially own the units held by CheniereLNG 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 orthrough Cheniere Subsidiary Holdings, LLC, Cheniere Common Units Holding, LLC and Cheniere Class B Units Holding, LLC each a whollyowned subsidiary, and may, therefore, be deemed to beneficially own the units held by Cheniere Subsidiary Holdings, LLC, Cheniere Common UnitsHolding, 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 connectionwith Blackstone CQP Holdco LP's purchase of Class B units. 98Equity 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 tableprovides certain information as of December 31, 2012 with respect to this plan: Plan Category Number of securities to be issuedupon exercise of outstandingoptions, warrants and rights (1) Weighted-average exercise priceof outstandingoptions, warrants and rights Number of securities remaining availablefor future issuance under equitycompensation plans (excluding securitiesreflected in the first column)Equity compensation plans approved bysecurity holders — N/A — Equity compensation plans not approvedby security holders — N/A 1,250,000Total — 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 onsuch 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 TransactionsPrior to the completion of our initial public offering of common units in 2007, the managers of our general partner approved the distributions andpayments to be made to our general partner and its affiliates in connection with our ongoing operations and, in the event of, our liquidation. During ouroperational stage, we will generally make cash distributions to our unitholders, including our affiliates, as described in Part II, Item 5, of this annual report onForm 10-K. Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respectivecapital 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 relatedfinancial transactions, arrangements or relationships between the partnership and any related-party, if the amount involved exceeds $120,000 and suchtransactions 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 byreference. Except as described below, such related-party transactions were approved by the members of the board of directors of our general partner, whichincludes 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") MasterAgreement 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 theevent Sabine Pass LNG chooses to hedge some of its LNG purchases or gas sales and elects to implement such hedges through Cheniere Marketing, whichalready has ISDA agreements in place with third parties and accounts with futures brokers. There are no current transactions under this agreement. Noamounts were paid to Cheniere Marketing under this agreement during the fiscal years ended December 31, 2012 and 2011. 99Operational Balancing Agreement In December 2007, Sabine Pass LNG and Cheniere Creole Trail Pipeline, L.P. entered into an Operational Balancing Agreement that provides for theresolution 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 arate 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 themonth following termination. This agreement became effective following the achievement of commercial operability of the Sabine Pass LNG terminal inSeptember 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, 2012and 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 theability to export LNG from the Sabine Pass LNG terminal. Sabine Pass LNG recorded revenues—affiliate of $0.3 million pursuant to this agreement in theyears 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 AgreementIn July 2007, Sabine Pass LNG entered into Cooperative Endeavor Agreements with various Cameron Parish, Louisiana taxing authorities and a relatedagreement with Cheniere Marketing, each as described in Note 13—"Related Party Transactions" of our Notes to Consolidated Financial Statements. Duringeach 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 AgreementIn August 2010, Sabine Pass LNG entered into an agreement with its TUA customers, including Cheniere Energy Investments, LLC ("CheniereInvestments"), to share in the cost for the installation and operation of a temporary pipeline compressor at the Sabine Pass LNG terminal. Sabine Pass LNGrecorded 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 endedDecember 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 ofdirectors who meet the criteria for independence required by NYSE MKT. The board of our general partner has determined that Mike Bock, Lon McCain andRobert Sutcliffe are independent directors in accordance with the following NYSE MKT independence standards. A director would not be independent if anyof 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 partnershipor general partner; •a director who accepts, or has an immediate family member who accepts, any compensation from the partnership, general partner or any parent orsubsidiary of the partnership or general partner in excess of $120,000 during any twelve consecutive-month period or any of the past three fiscalyears, other than compensation for board or committee services, or compensation paid to an immediate family member who is a non-executiveemployee 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 towhich the partnership, general partner or any parent or subsidiary of the partnership or general partner made, or from which the partnership, generalpartner or any parent or subsidiary of the partnership or general partner received, payments (other than those arising solely from investments in ourcommon units or payments100under 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 mostrecent three fiscal years any of the executive officers of the partnership, general partner or any parent or subsidiary of the partnership or generalpartner 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 orsubsidiary of the partnership or general partner, or was a partner or employee of the outside auditor of the partnership, general partner or any parentor 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 feespaid to Ernst & Young LLP for professional services rendered for 2012 and 2011: Ernst & Young LLP Fiscal 2012 Fiscal 2011Audit Fees $1,376,834 $1,062,227Audit-Related Fees 253,777 171,767Total $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 allother 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 registrationstatement. 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-auditservices to be provided by the independent accountants and the fees for such services. Pre-approval of non-audit services (other than review and attestationservices) 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 fiscalyears 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.55Reports of Independent Registered Public Accounting Firm—Ernst & Young LLP56Consolidated Balance Sheets58Consolidated Statements of Operations59Consolidated Statements of Partners’ and Owners’ Capital (Deficit)61Consolidated Statements of Cash Flows62Notes to Consolidated Financial Statements63Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data88 101(2)Financial Statement Schedules:Schedule I—Condensed Financial Information of Registrant for the years ended December 31, 2012, 2011 and 2010108(3)Exhibits Exhibit No. Description2.1* Contribution and Conveyance Agreement. (Incorporated by reference to Exhibit 10.4 to Cheniere Energy Partners, L.P.'s Current Report onForm 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), filedon 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.'sRegistration 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), filedon 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 onNovember 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 timeto 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 Reporton 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 theretofrom 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 onNovember 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 onMarch 10, 2005) 10.3* Amendment of LNG Terminal Use Agreement, dated June 15, 2010, by and between Total Gas & Power North America, Inc. and SabinePass 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. (Incorporatedby reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed onNovember 2, 2012)102 10.5* Omnibus Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (Incorporated byreference 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 toCheniere 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 byreference 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 onAugust 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 toExhibit 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 byreference to Exhibit 10.12 to Sabine Pass LNG, L.P.'s Registration Statement on Form S-4 (SEC File No. 333-138916), filed on November22, 2006) 10.12* Second Amended and Restated Terminal Use Agreement, dated as of July 31, 2012, between Sabine Pass LNG, L.P. and Sabine PassLiquefaction, 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 byreference 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 10.7to 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 NaturalAprovisionamientos SDG S.A. (Buyer). (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.'s Current Report onForm 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 GasCorporation (Buyer). (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.'s Current Report on Form 8-K (SEC FileNo. 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). 10310.21* LNG Sale and Purchase Agreement (FOB), dated May 14, 2012, by and between Sabine Pass Liquefaction, LLC and CheniereMarketing, 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 Form8-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, datedNovember 11, 2011, between Sabine Pass Liquefaction, LLC and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit havebeen omitted and filed separately with the SEC pursuant to the SEC's grant of a confidential treatment request.) (Incorporated by referenceto 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 LNGLiquefaction 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 RemovalUnit, dated May 23, 2012, (iii) the Change Order CO-0003 LNTP, dated June 6, 2012, (iv) the Change Order CO-0004 Addition of InletAir Humidification, dated July 10, 2012, (v) the Change Order CO-0005 Replace Natural Gas Generators with Diesel Generators, datedJuly 10, 2012, (vi) the Change Order CO-0006 Flange Reduction and Valve Positioners, dated July 12, 2012, and (vii) the Change OrderCO-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 (SECFile 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 LNGLiquefaction 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 HAZOPAction Items, dated July 31, 2012, (iii) the Change Order CO-0010 Fuel Provisional Sum, dated August 8, 2012, (iv) the Change OrderCO-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 CheniereEnergy 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 LNGLiquefaction 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 CoolerWalkways, 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 PowerRequirements, dated January 17, 2013. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a requestfor 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 thisexhibit have been omitted and filed separately with the SEC pursuant to the SEC’s grant of a confidential treatment request.) (Incorporatedby 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 December27, 2012) 10.29* LNG Lease Agreement, dated June 24, 2008, between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (Incorporated by reference toExhibit 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 onNovember 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 collateraltrustee, Sabine Pass LNG-GP, Inc. and Sabine Pass LNG-LP, LLC. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.'sCurrent Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006) 10410.32* Amended and Restated Parity Lien Security Agreement, dated November 9, 2006, by and between Sabine Pass LNG, L.P. and The Bankof New York, as collateral trustee. (Incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.'s Current Report on Form 8-K (SECFile 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 November9, 2006, between the Sabine Pass LNG, L.P. and The Bank of New York, as collateral trustee. (Incorporated by reference to Exhibit 10.3to 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 PassLNG-GP, Inc., Sabine Pass LNG-LP, LLC and The Bank of New York, as collateral trustee. (Incorporated by reference to Exhibit 10.4 toCheniere 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 collateraltrustee, and The Bank of New York, as depositary agent. (Incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.'s CurrentReport 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 amongCheniere LNG O&M Services, LLC, Cheniere Energy Partners GP, LLC and Sabine Pass LNG, L.P. (Incorporated by reference toExhibit 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. andSabine 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&MServices, LLC, Cheniere Energy Partners GP, LLC and Sabine Pass Liquefaction, LLC. (Incorporated by reference to Exhibit 10.5 toCheniere 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, LLCand Cheniere Energy Partners GP, LLC. (Incorporated by reference to Exhibit 10.3 to Cheniere Energy Partners, L.P.’s Quarterly Report onForm 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 EnergyPartners, L.P., Cheniere LNG Terminals, Inc. and Cheniere Energy, Inc. (Incorporated by reference to Exhibit 10.4 to Cheniere EnergyPartners, 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) LLCand 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), filedon February 4, 2013) 10.44* Unit Purchase Agreement, dated May 14, 2012, by and among Cheniere Energy Partners, L.P., Cheniere Energy, Inc. and BlackstoneCQP 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 HoldcoLP. (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) 10510.46* Class B Unit Purchase Agreement, dated as of May 14, 2012, by and between Cheniere Energy Partners, L.P. and Cheniere LNGTerminals, 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. andCheniere Class B Units Holdings, LLC. (Incorporated by reference to Exhibit 10.3 to Cheniere Energy Partners, L.P.'s Current Report onForm 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 investorsparty thereto from time to time. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.’s Current Report on 8-K (SECFile 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 toCheniere 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), filedon 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 AAdministrative Agent and Common Security Trustee, and the lenders party thereto from time to time. (Incorporated by reference to Exhibit10.4 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 GroupRepresentatives, 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 (SECFile 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 toCheniere 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 toCheniere 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 CheniereEnergy 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 EnergyPartners, 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 EnergyPartners, 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 toCheniere Energy Partners, L.P.'s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on March 2, 2007) 10610.60*† Form of Phantom Units Agreement for employees, consultants and directors (three-year). (Incorporated by reference to Exhibit 10.45 toCheniere 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 Form8-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 QuarterlyReport 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 toExhibit 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). (Incorporatedby reference to Exhibit 10.9 to Cheniere Energy Partners, L.P.’s Quarterly Report on Form 10-Q (SEC File No. 001-33366), filed onNovember 2, 2012) 10.65*† Summary of Compensation for Independent Directors. (Incorporated by reference to Exhibit 10.1 to Cheniere Energy Partners, L.P.'sCurrent 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 toExhibit 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-OxleyAct 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-OxleyAct 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 aregistration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are deemednot filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject toliability under those sections.107SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—CHENIERE ENERGY PARTNERS, L.P.CONDENSED BALANCE SHEET(in thousands) December 31, 2012 2011ASSETS Current assets Cash and cash equivalents $392,945 $56,119Advances to affiliate — 136Prepaid expenses and other 134 135Total current assets 393,079 56,390 Investment in affiliates 972,395 —Non-current receivable—affiliates 940 47,238Other 874 —Total assets $1,367,288$103,628 LIABILITIES AND STOCKHOLDERS’ DEFICIT Current liabilities $4,480 $3,806Equity in losses of affiliates — 644,841Commitments and contingencies Stockholders' equity (deficit) 1,362,808 (545,019)Total liabilities and stockholders’ deficit $1,367,288 $103,628See accompanying notes to condensed financial statements.108SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—CHENIERE ENERGY PARTNERS, L.P.CONDENSED STATEMENT OF OPERATIONS(in thousands) Year Ended December 31, 2012 2011 2010Revenues $— $— $—Operating costs and expenses 18,262 13,104 14,723Loss from operations (18,262) (13,104) (14,723)Interest expense, net 12 — —Interest income 235 38 51Equity income (loss) of affiliates (132,121) (17,953) 122,240Net income (loss) $(150,136) $(31,019) $107,568See accompanying notes to condensed financial statements.109SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT—CHENIERE ENERGY PARTNERS, L.P.CONDENSED STATEMENT OF CASH FLOWS(in thousands) Year Ended December 31, 2012 2011 2010Cash 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 59,910 229,608Distributions 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 26,352Cash and cash equivalents—beginning of year 56,119 26,482 130Cash and cash equivalents—end of year $392,945 $56,119 $26,482See accompanying notes to condensed financial statements.110CHENIERE 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 forCheniere 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 thismethod, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are recorded in the balance sheets. Thegain/(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 financialstatements 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. 111SIGNATURESPursuant 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 itsbehalf 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 generalpartner of the registrant and in the capacities and on the dates indicated.SignatureTitleDate /s/ Charif SoukiChief Executive Officer & Chairman of the BoardFebruary 22, 2013Charif Souki(Principal Executive Officer) /s/ R. Keith TeaguePresident and Chief Operating Officer,February 22, 2013R. Keith TeagueDirector (Principal Operating Officer) /s/ Meg A. GentleSenior Vice President & Chief Financial Officer,February 22, 2013Meg A. GentleDirector (Principal Financial Officer) /s/ Jerry D. SmithChief Accounting OfficerFebruary 22, 2013Jerry D. Smith(Principal Accounting Officer) /s/ James R. BallDirectorFebruary 22, 2013James R. Ball /s/ David I. FoleyDirectorFebruary 22, 2013David I. Foley /s/ Sean T. KlimczakDirectorFebruary 22, 2013Sean T. Klimczak /s/ Lon McCainDirectorFebruary 22, 2013Lon McCain /s/ Vincent Pagano Jr.DirectorFebruary 22, 2013Vincent Pagano Jr. /s/ Oliver G. Richard, IIIDirectorFebruary 22, 2013Oliver G. Richard, III /s/ H. Davis ThamesDirectorFebruary 22, 2013H. Davis Thames 112EXHIBIT 10.18AMENDMENT NO. 1 OF LNG SALE AND PURCHASE AGREEMENTTHIS AMENDMENT NO. 1 OF LNG SALE AND PURCHASE AGREEMENT (“Amendment”) is made and entered intoas of February 18, 2013, by and between Sabine Pass Liquefaction, LLC, a Delaware limited liability company whose principal place ofbusiness is located at 700 Milam St., Suite 800, Houston, TX 77002 (“Seller”), and GAIL (India) Limited, a company incorporated andexisting under the laws of India whose principal place of business is located at 16, Bhikaiji Cama Place, R.K. Puram, New Delhi, India110066 (“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 Agreementregarding certain conditions precedent, start-up timing, and other terms, all as set forth herein.It is agreed:1.DefinitionsCapitalized terms used in or incorporated into this Amendment and not otherwise defined herein have the meanings given tothem in the Agreement.2.Amendments2.1.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 “DesignatedTrain”, and the following definition is inserted in lieu thereof:Designated Train:(i) the second (2nd) Train to be constructed at the Sabine Liquefaction Facilitypursuant to the Lump Sum Turnkey Agreement for the Engineering,Procurement and Construction of the Sabine Pass LNG Stage 2 LiquefactionFacility dated December 20, 2012, between Seller and Bechtel Oil, Gas andChemicals, Inc.; (ii) in the event that the agreement described in clause (i)were to be terminated and a replacement engineering, procurement andconstruction contract were to be entered into by Seller for the third (3rd) andfourth (4th) Trains to be constructed at- 1 -the Sabine Liquefaction Facility, the second (2nd) Train to beconstructed pursuant to such contract; or (iii) in the event that the agreementdescribed in clause (i) were to be terminated and a replacement engineering,procurement and construction contract were to be entered into by Sellersolely for the fourth (4th) Train to be constructed at the Sabine LiquefactionFacility, 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;and2.5.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 anyother facilities at the Sabine Pass Facility needed to enable Seller to fulfill its obligations under thisAgreement, an unconditional full notice to proceed with the construction of the Designated Train andany other facilities at the Sabine Pass Facility needed to enable Seller to fulfill its obligations under thisAgreement.2.6.Section 2.2.3 of the Agreement is amended by deleting the words “June 30th, 2013” and replacing them with the words“December 31st, 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:4.2.1The period that begins on the first Day of the Month that follows the date that is fifty-seven (57) Months afterthe 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.Miscellaneous3.1.Dispute Resolution; Immunity. The provisions of Section 21.1 (Dispute Resolution) and Section 21.4 (Immunity) of theAgreement shall apply in this Amendment as if incorporated herein mutatis mutandis on the basis that references therein to theAgreement 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 andincludes 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 instrumentin 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 toenforce such right or remedy.3.5.Counterparts. This Amendment may be executed in two counterparts and each such counterpart shall be deemed an originalAmendment for all purposes, provided that neither Party shall be bound to this Amendment unless and until both Parties haveexecuted 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 VedvyasName: H. Davis Thames Name: Rajesh VedvyasTitle: Executive Vice President Title: Executive Director- 4 -EXHIBIT 10.19 AMENDMENT NO. 1 OF LNG SALE AND PURCHASE AGREEMENTTHIS AMENDMENT NO. 1 OF LNG SALE AND PURCHASE AGREEMENT (“Amendment”) is made and entered intoas of February 18, 2013, by and between Sabine Pass Liquefaction, LLC, a Delaware limited liability company whose principal place ofbusiness is located at 700 Milam St., Suite 800, Houston, TX 77002 (“Seller”), and Korea Gas Corporation, a corporation organizedunder 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” andcollectively 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 Agreementregarding certain conditions precedent, start-up timing, and other terms, all as set forth herein.It is agreed:1.DefinitionsCapitalized terms used in or incorporated into this Amendment and not otherwise defined herein have the meanings given tothem in the Agreement.2.Amendments2.1.Section 1.1 of the Agreement is amended by deleting in its entirety the definition of “Designated Train”, and the followingdefinition is inserted in lieu thereof:Designated Train:the first (1st) LNG production train to be constructed at the SabineLiquefaction Facility pursuant to the Lump Sum Turnkey Agreement for theEngineering, Procurement and Construction of the Sabine Pass LNG Stage 2Liquefaction Facility dated December 20, 2012, between Seller and BechtelOil, Gas and Chemicals, Inc., including those facilities included in the SabinePass Facility that are necessary to enable Seller to fulfill its obligations toBuyer 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;and2.4.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 anyother facilities at the Sabine Pass Facility needed to enable Seller to fulfill its obligations under thisAgreement, an unconditional full notice to proceed with the construction of the Designated Train andany other facilities at the Sabine Pass Facility needed to enable Seller to fulfill its obligations under thisAgreement.2.5.Section 2.2.3 of the Agreement is amended by deleting the words “June 30th, 2013” and replacing them with the words“December 31st, 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 andreplacing 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.Miscellaneous3.1.Dispute Resolution; Immunity. The provisions of Section 21.1 (Dispute Resolution) and Section 21.4 (Immunity) of theAgreement shall apply in this Amendment as if incorporated herein mutatis mutandis on the basis that references therein to theAgreement 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 andincludes 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 instrumentin 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 toenforce such right or remedy.3.5.Counterparts. This Amendment may be executed in two counterparts and each such counterpart shall be deemed an originalAmendment for all purposes, provided that neither Party shall be bound to this Amendment unless and until both Parties haveexecuted 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 SikName: H. Davis Thames Name: Kwon, Young SikTitle: Executive Vice President Title: EVP, Resources Business Division- -4 -EXHIBIT 10.26CHANGE ORDER FORMCOP Technical Bulletin #4, Stage 2 Flare Tie-Ins, Additional DCS Furniture, Non-Redline ItemsPROJECT NAME: Sabine Pass LNG Liquefaction FacilityOWNER: Sabine Pass Liquefaction, LLCCONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.DATE OF AGREEMENT: November 11, 2011CHANGE ORDER NUMBER: CO-00014DATE OF CHANGE ORDER: September 5, 2012The 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 stainlesssteel in the refrigeration compressor suction piping and associated flanges. A copy of COP Bulletin #4 is attached as Exhibit A to this Change Order. ThisChange Order also includes the additional controls associated with COP Technical Bulletin #4 recommended by COP to Cheniere. The additional controlslist 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 0755b.Two (2) additional displays for HIS 0756c.Two (2) additional displays for HIS 0757d.Two (2) additional displays for HIS 0758e.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 systemcurrently 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 toavoid 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 asfollows:a.Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the Milestone(s) listed in Exhibit Eof 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 OrderAdjustment to Contract PriceThe original Contract Price was................................................................................................................................$3,900,000,000Net change by previously authorized Change Orders (#0001-00013) .....................................................................$ 59,649,341The Contract Price prior to this Change Order was..................................................................................................$3,959,649,341The Contract Price will be (increased) by this Change Orderin the amount of .......................................................................................................................................................$ 7,125,052The new Contract Price including this Change Order will be..................................................................................$3,966,774,393Adjustment to dates in Project ScheduleThe 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/AAdjustment to Performance Guarantees: N/AAdjustment to Design Basis: N/AOther adjustments to liability or obligation of Contractor or Owner under the Agreement: N/ASelect 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 uponthe 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 Orderupon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ OwnerUpon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreementwithout exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other termsand 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. JacksonOwner ContractorEd Lehotsky JT JacksonName NameVP LNG Project Management Sr. Vice PresidentTitle TitleSeptember 26, 2012 September 7, 2012Date of Signing Date of Signing CHANGE ORDER FORMLNG Static Mixer, Additional Walkways for Hudson Coolers, Early EPC Additional Reimbursement, Creditto Change Order 00014 NegotiationPROJECT NAME: Sabine Pass LNG Liquefaction FacilityOWNER: Sabine Pass Liquefaction, LLCCONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.DATE OF AGREEMENT: November 11, 2011CHANGE ORDER NUMBER: CO-00015DATE 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 WestJetty locations in the Existing Facility. This work was previously within Sabine Pass Liquefaction, LLC's scope and therefore excluded from the LSTKproposal 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 fabricatedin 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” indiameter 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. Finalassessment 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 revisedLNG 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 TwoMillion, One Hundred Ninety Four Thousand, Four Hundred and Forty Four U.S. Dollars ($262,194,444). This Change Order will amendthat 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 forplant 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 sumincrease and $346,307 increase in aggregate provisional sum as noted in Section 1.e of this Change Order. Accordingly, the Agreement is modified asfollows:a.Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the Milestone(s) listed in Exhibit Aof 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 PriceThe original Contract Price was ...............................................................................................................................$3,900,000,000Net change by previously authorized Change Orders (#0001-00014) .....................................................................$ 66,774,393The Contract Price prior to this Change Order was .................................................................................................$3,966,774,393The Contract Price will be (increased) by this Change Orderin the amount of.........................................................................................................................................................$ 2,551,141The new Contract Price including this Change Order will be ..................................................................................$3,969,325,534Adjustment to dates in Project ScheduleThe 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/AAdjustment to Performance Guarantees: N/AAdjustment to Design Basis: N/AOther adjustments to liability or obligation of Contractor or Owner under the Agreement: N/ASelect 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 andsatisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for suchchange. 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 Orderupon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ OwnerUpon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreementwithout exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other termsand 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 BuoncristianoOwner ContractorEd Lehotsky Segio BuoncristianoName NameVP LNG Project Management Principal Vice PresidentTitle TitleNovember 20, 2012 November 9, 2012Date of Signing Date of SigningCHANGE ORDER FORMSecond Delay in Full Placement of Insurance ProgramPROJECT NAME: Sabine Pass LNG Liquefaction FacilityOWNER: Sabine Pass Liquefaction, LLCCONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.DATE OF AGREEMENT: November 11, 2011CHANGE ORDER NUMBER: CO-0016DATE OF CHANGE ORDER: October 29, 2012The 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 laterMarch 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 andnamed windstorm with a sub-limit not less than $150,000,000 commencing at LNTP, provided that such sub-limit shall increase to anamount 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 namedwindstorm shall apply to the combined loss covered under Section 1.A.9 Builder's Risk and Section 1.A.10 Builder's Risk DelayedStartup, and (vi) insure loss or damage from strikes, riots and civil commotion with a sub-limit not less than $100,000,000.2.Section 1.3 of Attachment EE is hereby amended as follows:1.3 Insurance Provisional SumThe Aggregate Provisional Sum contains a Provisional Sum of *** U.S. Dollars (U.S.$***) (“Insurance Provisional Sum”) for the cost ofinsurance premiums for the insurance required to be provided by Contractor in accordance with Attachment O (other than workers compensation andemployer liability insurance) (the “Project Insurances”). Contractor shall notify Owner in writing no later than March 31, 2013 of the actual cost ofthe insurance premiums charged to Contractor by Contractor's insurance carrier for the Project Insurances (“Actual Insurance Cost”), which ActualInsurance Cost shall be adequately documented by Contractor. If the Actual Insurance Cost is less than the Insurance Provisional Sum, Owner shallbe entitled to a Change Order reducing the Contract Price by such difference. If the Actual Insurance Cost is greater than the Insurance ProvisionalSum, Contractor shall be entitled to a Change Order increasing the Contract Price by such difference. Contractor shall be responsible for theplacement of the Project Insurances required to be provided by Contractor in accordance with Attachment O, provided that Contractor shallreasonably 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 excessliability policies specified in Section 1A.2 and 1A.4 of Attachment O and providing sudden and accidental pollution liability coverage (includingclean up on or off the Site) under such commercial general liability policy. Accordingly, should (i) the insurance provider(s) charge any additionalpremium 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 andaccidental liability coverage and, instead, is required to procure a stand-alone pollution policy, Contractor shall be entitled to a Change Orderincreasing the Contract Price in the actual amount of such increased premium associated with naming the Owner Group as named insureds ratherthan additional insureds or procurement of such stand-alone pollution policy.Adjustment to Contract PriceNo Adjustment to Contract Price associated with CO-00016Adjustment to dates in Project ScheduleThe following dates are modified (list all dates modified; insert N/A if no dates modified): N/AAdjustment to other Changed Criteria: if no changes or impact; attach additional documentation if necessary): N/AAdjustment to Payment Schedule: N/AAdjustment to Minimum Acceptance Criteria: N/AAdjustment to Performance Guarantees: N/AAdjustment to Design Basis: N/AOther adjustments to liability or obligation of Contractor or Owner under the Agreement: N/ASelect 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 uponthe 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 Orderupon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ OwnerUpon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreementwithout exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other termsand 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. JacksonOwner ContractorEd Lehotsky JT JacksonName NameVP LNG Project Management Sr. Vice PresidentTitle TitleNovember 7, 2012 October 29, 2012Date of Signing Date of SigningCHANGE ORDER FORMCondensate HeaderPROJECT NAME: Sabine Pass LNG Liquefaction FacilityOWNER: Sabine Pass Liquefaction, LLCCONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.DATE OF AGREEMENT: November 11, 2011CHANGE ORDER NUMBER: CO-00017DATE OF CHANGE ORDER: December 3, 2012The 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 andterminating 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 locationsoutheast 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 thisChange 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 shownin 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 forfour (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 shownin 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, FiveHundred Forty Thousand, Seven Hundred and Fifty One U.S. Dollars ($262,540,751). This Change Order will amend that value and the newvalue 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 ofTrain 1.b.No off-specification condensate handling system will be provided. Handling of off-specificationcondensate 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 thebattery 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 leveloriginally 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'sresponsibility 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 revieware 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, theAgreement 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 Fof 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 PriceThe original Contract Price was................................................................................................................................$3,900,000,000Net change by previously authorized Change Orders (#0001-00016) .....................................................................$ 69,325,534The Contract Price prior to this Change Order was...................................................................................................$3,969,325,534The Contract Price will be (increased) by this Change Orderin the amount of.........................................................................................................................................................$ 2,534,523The new Contract Price including this Change Order will be...................................................................................$3,971,860,057Adjustment to dates in Project ScheduleThe 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/AAdjustment to Performance Guarantees: N/AAdjustment to Design Basis: N/AOther adjustments to liability or obligation of Contractor or Owner under the Agreement: N/ASelect 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 uponthe 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 Orderupon the Changed Criteria and shall not be deemed to compensate Contractor fully for such change. Initials: ____ Contractor ____ OwnerUpon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreementwithout exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other termsand 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. JacksonOwner ContractorEd Lehotsky JT JacksonName NameVP LNG Project Management Sr. Vice PresidentTitle TitleDecember 21, 2012 December 12, 2012Date of Signing Date of SigningCHANGE ORDER FORMIncrease in Power Requirements to Cheniere BuildingsPROJECT NAME: Sabine Pass LNG Liquefaction FacilityOWNER: Sabine Pass Liquefaction, LLCCONTRACTOR: Bechtel Oil, Gas and Chemicals, Inc.DATE OF AGREEMENT: November 11, 2011CHANGE ORDER NUMBER: CO-00018DATE OF CHANGE ORDER: January 17, 2013The Agreement between the Parties listed above is changed as follows: (attach additional documentation ifnecessary)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 theO&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 powerrequirements. 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 sumincrease and an $83,014 increase in aggregate provisional sum as noted in item 5 of this Change Order. Accordingly, the Agreement is modified asfollows:a.Schedule C-1 (Milestone Payment Schedule) of Attachment C of the Agreement will be amended by including the Milestone(s) listed in ExhibitB of this Change Order.4.The previous Existing Facility Labor Provisional Sum in Article 2.2 of Attachment EE of the Agreement was to U.S. Dollars ($***) 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 HundredEighty Four Thousand, Three Hundred Seventy Seven U.S. Dollars ($263,584,377). This Change Order will amend that value and the new valueshall 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 Dof this Change Order.Adjustment to Contract PriceThe original Contract Price was .............................................................................................................................$3,900,000,000Net change by previously authorized Change Orders (#0001-00017)....................................................................$ 71,860,057The Contract Price prior to this Change Order was ...............................................................................................$3,971,860,057The Contract Price will be (increased) by this Change Orderin the amount of .....................................................................................................................................................$ 681,444The new Contract Price including this Change Order will be ................................................................................$3,972,541,501Adjustment to dates in Project ScheduleThe following dates are modified (list all dates modified; insert NIA if no dates modified): No impact to ProjectSchedule.Adjustment to other Changed Criteria (insert NIA if no changes or impact; attach additional documentation ifnecessary)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/AAdjustment to Performance Guarantees: N/AAdjustment to Design Basis: N/AOther adjustments to liability or obligation of Contractor or Owner under the Agreement: N/ASelect either A orB:. .[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of thechange 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 thechange reflected in this Change Order upon tanged Criteria and shall not be deemed to compensate Contractor fully for such change. Initials:____Contractor _____ OwnerUpon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreementwithout exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other termsand 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 BuoncristianoOwner ContractorEd Lehotsky Segio BuoncristianoName NameVP LNG Project Management Principal Vice PresidentTitle TitleFebruary 4, 2013 January 18, 2013Date of Signing Date of SigningEXHIBIT 21.1 List of Subsidiaries or Other Related Entities of Company Cheniere Energy Investments, LLCCheniere Midstream Services, LLCCheniere NGL Pipeline, LLCSabine Pass Liquefaction, LLCSabine Pass Liquefaction Expansion, LLCSabine Pass LNG-GP, LLCSabine Pass LNG-LP, LLCSabine Pass LNG, L.P.Sabine Pass Liquefaction, LLCSabine Pass Liquefaction Expansion, LLCSabine Pass Tug Services, LLCEXHIBIT 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe 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. andsubsidiaries, and the effectiveness of internal control over financial reporting of Cheniere Energy Partners, L.P. and subsidiaries, included in this AnnualReport (Form 10-K) for the year ended December 31, 2012./s/ ERNST & YOUNG LLPErnst & Young LLPHouston, TexasFebruary 22, 2013EXHIBIT 31.1CERTIFICATION BY CHIEF EXECUTIVE OFFICER PURSUANT TORULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACTI, 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 thestatements 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 thefinancial 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 ExchangeAct 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 theregistrant and have:a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, 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 inaccordance 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 effectivenessof 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 fiscalquarter (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; and5.The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant'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 likelyto adversely affect the registrant's ability to record, process, summarize and report financial information; andb)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control overfinancial reporting.Date: February 22, 2013 /s/ CHARIF SOUKICharif SoukiChief Executive Officer of Cheniere Energy Partners GP, LLC, thegeneral partner of Cheniere Energy Partners, L.P.EXHIBIT 31.2CERTIFICATION BY CHIEF FINANCIAL OFFICERPURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACTI, 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 thestatements 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 thefinancial 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 ExchangeAct 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 theregistrant and have:a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, 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 inaccordance 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 effectivenessof 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 fiscalquarter (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; and5.The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant'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 likelyto adversely affect the registrant's ability to record, process, summarize and report financial information; andb)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control overfinancial reporting.Date: February 22, 2013 /s/ MEG A. GENTLEMeg A. GentleChief Financial Officer of Cheniere Energy Partners GP, LLC, thegeneral partner of Cheniere Energy Partners, L.P.Exhibit 32.1CERTIFICATION BY CHIEF EXECUTIVE OFFICERPURSUANT TO 18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In 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 filedwith the Securities and Exchange Commission on the date hereof (the “Report”), I, Charif Souki, Chief Executive Officer of the general partner of thePartnership, 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 SOUKICharif SoukiChief Executive Officer of Cheniere Energy Partners GP, LLC, thegeneral partner of Cheniere Energy Partners, L.P.EXHIBIT 32.2CERTIFICATION BY CHIEF FINANCIAL OFFICERPURSUANT TO 18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In 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 filedwith the Securities and Exchange Commission on the date hereof (the “Report”), I, Meg A. Gentle, Chief Financial Officer of the general partner of thePartnership, 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. GENTLEMeg A. GentleChief Financial Officer of Cheniere Energy Partners GP, LLC, thegeneral partner of Cheniere Energy Partners, L.P.Contacts & Advisors Corporate Office Cheniere Energy Partners, L.P. 700 Milam, Suite 800 Houston, Texas 77002 Telephone: (713) 375-5000 Facsimile: (713) 375-6000 Stock Exchange Listing: NYSE MKT: CQP Investor Relations Telephone: (713) 375-5100 Email: info@cheniere.com www.cheniereenergypartners.com Transfer Agent Computershare Trust Company, N.A. P.O. Box 43078 Providence, RI 02940-3078 Telephone: (800) 962-4284 Facsimile: (303) 262-0600 Independent Accountants Ernst & Young, LLP Houston, Texas CORPORATE INFORMATION Board of Directors & Officers Charif Souki Chairman and Chief Executive Officer James R. Ball Independent Director Daniel Belhumeur Vice President and General Tax Counsel Cara Carlson Corporate Secretary David I. Foley Director Meg A. Gentle Director, Senior Vice President and Chief Financial Officer Sean T. Klimczak Director Graham A. McArthur Vice President and Treasurer Lon McCain Independent Director Vincent Pagano, Jr. Independent Director Oliver G. Richard, III Independent Director Jerry Smith Chief Accounting Officer Keith Teague Director, President and Chief Operating Officer Davis Thames Director CHENIERE ENERGY PARTNERS, L.P. 2012 ANNUAL REPORT

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