CQP 2011 Form 10K



 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
 
Commission File No. 001-33366 
CHENIERE ENERGY PARTNERS, L.P. 
(Exact name of registrant as specified in its charter)
Delaware
 
20-5913059
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
700 Milam Street, Suite 800
 
 
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip code)
 
Registrant’s telephone number, including area code: (713) 375-5000
Securities registered pursuant to Section 12(b) of the Act:
Common Units Representing Limited
Partner Interests
NYSE Amex Equities
(Title of Class)
(Name of each exchange on which registered)
 
Securities registered pursuant to Section 12(g) of the Act: None 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes o    No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.    Yes o    No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes x    No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes x   No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  o
 
Accelerated filer  x
Non-accelerated filer  o
 
Smaller reporting company  o
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o    No  x
The aggregate market value of the registrant’s Common Units held by non-affiliates of the registrant was approximately $288 million as of June 30, 2011.
The issuer had 31,003,154 common units and 135,383,831 subordinated units outstanding as of February 15, 2012.
Documents incorporated by reference: None  

 



CHENIERE ENERGY PARTNERS, L.P
TABLE OF CONTENTS






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CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS


This annual report contains certain statements that are, or may be deemed to be, "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical facts, included herein or incorporated herein by reference are "forward-looking statements." Included among "forward-looking statements" are, among other things:
 
statements regarding our ability to pay distributions to our unitholders; 
statements regarding our expected receipt of cash distributions from Sabine Pass LNG, L.P. ("Sabine Pass LNG"); 
statements regarding future levels of domestic natural gas production, supply or consumption; future levels of liquefied natural gas ("LNG") imports into North America; sales of natural gas in North America or other markets; exports of LNG from North America; and the transportation, other infrastructure or prices related to natural gas, LNG or other energy sources; 
statements regarding any financing or refinancing transactions or arrangements, or ability to enter into such transactions or arrangements, whether on the part of Cheniere Energy Partners, L.P. or any subsidiary or at the project level; 
statements regarding any commercial arrangements presently contracted, optioned or marketed, or potential arrangements, to be performed substantially in the future, including any cash distributions and revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, liquefaction or storage capacity that are, or may become, subject to such commercial arrangements;
statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
statements relating to the construction and operations of our proposed LNG liquefaction facilities, including statements concerning the completion by certain dates or at all, the costs related thereto and certain characteristics, including amounts of liquefaction capacity and storage capacity and the number of LNG trains;
statements that we expect to receive an order from the Federal Energy Regulatory Commission ("FERC") authorizing us to construct and operate our proposed liquefaction facilities by certain dates, or at all;
statements regarding any business strategy, any business plans or any other plans, forecasts, projections or objectives, including potential revenues and capital expenditures, any or all of which are subject to change; 
statements regarding legislative, governmental, regulatory, administrative or other public body actions, requirements, permits, investigations, proceedings or decisions; and 
any other statements that relate to non-historical or future information.

These forward-looking statements are often identified by the use of terms and phrases such as "achieve," "anticipate," "believe," "contemplate," "develop," "estimate," "expect," "forecast," "plan," "potential," "project," "propose," "strategy" and similar terms and phrases, or by the use of future tense. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which are made as of the date of this annual report and speak only as of the date of this annual report.
 
Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in "Risk Factors." All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors.




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DEFINITIONS
 
In this annual report, unless the context otherwise requires: 
Bcf means billion cubic feet;
Bcf/d means billion cubic feet per day;
EPC means engineering, procurement and construction;
LNG means liquefied natural gas;
LNG train means an independent modular unit for gas liquefaction;
MMBtu means million British thermal units;
Mtpa means million metric tons per annum; and
TUA means terminal use agreement.
 
PART I
 
ITEMS 1. and 2.     BUSINESS AND PROPERTIES

General
 
We are a Delaware limited partnership formed by Cheniere Energy, Inc. ("Cheniere"). Through our wholly owned subsidiary, Sabine Pass LNG, we own and operate the Sabine Pass LNG terminal located in western Cameron Parish, Louisiana on the Sabine Pass Channel. The Sabine Pass LNG terminal has regasification capacity of approximately 4.0 Bcf/d and five LNG storage tanks with an aggregate LNG storage capacity of approximately 16.9 Bcf along with two unloading docks capable of handling the largest LNG carriers currently being operated or built. Approximately one-half of the receiving capacity at the Sabine Pass LNG terminal is contracted to two international oil companies. We are developing a project to add liquefaction capabilities at the Sabine Pass LNG terminal through a wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"). Unless the context requires otherwise, references to "Cheniere Partners", "we", "us" and "our" refer to Cheniere Energy Partners, L.P. and its subsidiaries, including Sabine Pass LNG. 

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

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




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Our Business Strategy 
Our primary business strategy is to identify markets in which the development of marine hydrocarbon terminals presents an opportunity to develop assets based on long-term, take-or-pay type contracts. Our initial development of the Sabine Pass LNG terminal, based on contracts with Chevron U.S.A. Inc. ("Chevron") and Total Gas and Power North America, Inc. ("Total"), has provided us with the opportunity to expand the terminal to add liquefaction capabilities. We plan to implement our strategy by:
safely maintaining and operating the Sabine Pass LNG terminal;
obtaining the requisite regulatory permits and financing to reach a final investment decision on our liquefaction project;
expanding the Sabine Pass LNG terminal to add liquefaction capabilities;
contracting for feed and fuel gas for our liquefaction project;
utilizing the 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal held by one of our wholly owned subsidiaries, Cheniere Energy Investments, LLC ("Cheniere Investments"), for short-term and spot LNG purchases and sales until such capacity is used in connection with our liquefaction project;
developing business relationships for the marketing of additional long-term and short- term agreements for excess LNG volumes at the Sabine Pass LNG terminal that have not been sold to our long-term customers, and for long-term; and
expanding our existing asset base through acquisitions from Cheniere or third parties or our own development of our liquefaction project or complementary businesses or assets such as other LNG terminals, natural gas storage assets and natural gas pipelines.

Market Factors

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

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

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

While global natural gas consumption is rising internationally, natural gas production in North America has undergone a technological transformation that has resulted in a substantial increase in annual production capacity, decrease in the cost of production, and expansion of technically recoverable reserves. Technologies related to both horizontal drilling and hydraulic



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fracturing, which had been under development since the 1980s, have now allowed the exploration and production industry to develop unconventional reservoirs composed predominantly of shales, but also containing tight sands and coal seam methane. Unconventional reservoirs are also known as continuous reservoirs; they extend over very large geographic sections of North America. The primary obstacle in the development of these resources is not about finding the formations, but about designing optimal well placement for their most efficient exploitation. This has been greatly facilitated by new drilling technologies that permit very deep and long horizontal wells with drill bores located at single drilling sites to minimize the cycle time between wells and the environmental impact of drilling operations.

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

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

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

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

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

Regasification Facilities

The Sabine Pass LNG terminal has operational regasification capacity of approximately 4.0 Bcf/d (with peak capacity of approximately 4.3 Bcf/d) and aggregate LNG storage capacity of approximately 16.9 Bcf. Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which Sabine Pass LNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Capacity reservation fee TUA payments are made by Sabine Pass LNG's third-party TUA customers as follows: 
Total has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions; and 



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

In November 2006, Cheniere Marketing, LLC ("Cheniere Marketing"), a wholly owned subsidiary of Cheniere, reserved approximately 2.0 Bcf/d of regasification capacity under a TUA and was obligated to make capacity payments to Sabine Pass LNG aggregating approximately $250 million per year for the period from January 1, 2009, through at least September 30, 2028. In June 2010, Cheniere Marketing assigned its TUA with Sabine Pass LNG to Cheniere Investments, including all of its rights, titles, interests, obligations and liabilities under the TUA. In connection with the assignment, Cheniere's guarantee of Cheniere Marketing's obligations under the TUA was terminated. Cheniere Investments is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year through at least September 30, 2028; however, the revenue earned by Sabine Pass LNG from Cheniere Investments' capacity payments under the TUA is eliminated upon consolidation of our financial statements. We have guaranteed Cheniere Investments' obligations under its TUA.

Concurrently with the TUA assignment, Cheniere Investments entered into a Variable Capacity Rights Agreement ("VCRA") with Cheniere Marketing in order for Cheniere Investments to monetize its capacity at the Sabine Pass LNG terminal. The VCRA will continue until the earliest of (a) the termination of Cheniere Investments' TUA, (b) expiration of the initial term of the TUA, (c) the termination of the VCRA by either party after June 2012, or (d) the termination of the VCRA as a result of default. Prior to 2018, Cheniere Marketing's termination right is subject to our having specified levels of cash reserved for distribution to our common unitholders as of the applicable termination date. Under the terms of the VCRA, Cheniere Marketing is responsible for monetizing the capacity at the Sabine Pass LNG terminal held by Cheniere Investments and has the right to utilize all of the services and other rights at the Sabine Pass LNG terminal available under the TUA assigned to Cheniere Investments. In consideration of these rights, Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG delivered to the Sabine Pass LNG terminal. To the extent payments from Cheniere Marketing to Cheniere Investments under the VCRA increase our available cash in excess of the common unit and general partner distributions and certain reserves, the cash would be distributed to Cheniere in the form of distributions on its subordinated units. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs under the TUA. Cheniere has guaranteed all of Cheniere Marketing's payment obligations under the VCRA. Cheniere Marketing continues to develop its business, lacks a credit rating and may be limited by access to capital. Cheniere, which has guaranteed the obligations of Cheniere Marketing under the VCRA, has a non-investment grade corporate rating.

Liquefaction Facilities

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

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

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

Customers

Sabine Pass Liquefaction has entered into four LNG sale and purchase agreements ("SPA"), under which customers have committed to purchase, in aggregate, 834.0 million MMBtu of LNG per year (approximately 16 mtpa). The volume of LNG committed to be purchased by these customers represents approximately 89% of the expected nameplate liquefaction capacity that will be available upon completion of our proposed liquefaction facilities. In addition, upon completion of all four LNG trains,



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approximately 100 million MMBtu of LNG per year (approximately 2.0 mtpa) may be produced seasonally to be sold by Sabine Pass Liquefaction on a merchant basis. We anticipate that Sabine Pass Liquefaction will utilize Cheniere Investments' TUA capacity to provide LNG to Sabine Pass Liquefaction's customers.
In aggregate, these customers have agreed to pay Sabine Pass Liquefaction approximately $2.3 billion annually, plus an amount per MMBtu of LNG equal to 115% of the final settlement price for the New York Mercantile Exchange natural gas futures contract for the month in which the relevant cargo is scheduled. Subject to the conditions described below, sales charges will be paid by our SPA customers as follows:
BG Gulf Coast LNG, LLC ("BG") has agreed to purchase 286.5 million MMBtu of LNG per year (approximately 5.5 mtpa) for a fixed sales charge of (i) $2.25 per MMBtu for 182.5 million MMBtu commencing upon the date of first commercial delivery for LNG train 1, (ii) $3.00 per MMBtu for 36.5 million MMBtu commencing upon the date of first commercial delivery for LNG train 2 (the "Train 2 Tranche"), (iii) $3.00 per MMBtu for 34.0 million MMBtu commencing upon the date of first commercial delivery for LNG train 3 (the "Train 3 Tranche") and (iv) $3.00 per MMBtu for 33.5 million MMBtu commencing upon the date of first commercial delivery for LNG train 4 (the "Train 4 Tranche"), plus in each case a contract sales price for each MMBtu of LNG delivered under the SPA equal to 115% of the final settlement price for the New York Mercantile Exchange Henry Hub natural gas futures contract for the month in which the relevant cargo is scheduled. The fixed sales charge is equivalent to approximately $411 million, $520 million, $622 million and $723 million per year upon completion of LNG trains 1, 2, 3 and 4, respectively, such that after completion of LNG train 4, the fixed sales charge will be a total of approximately $723 million per year;
Gas Natural Aprovisionamientos SDG S.A. ("Gas Natural Fenosa"), an affiliate of Gas Natural SDG S.A., has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa) for a fixed sales charge of $2.49 per MMBtu for the full contract quantity, plus a contract sales price for each MMBtu of LNG delivered under the SPA equal to 115% of the final settlement price for the New York Mercantile Exchange Henry Hub natural gas futures contract for the month in which the relevant cargo is scheduled. The fixed sales charge is equivalent to approximately $454 million per year, commencing upon the date of first commercial delivery for LNG train 2;
Korea Gas Corporation ("KOGAS") has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa) for a contract sales price equal to $3.00 plus 115% of the final settlement price for the New York Mercantile Exchange Henry Hub natural gas futures contract for the month in which the relevant cargo is scheduled. The fixed portion of the contract sales price is equivalent to approximately $548 million per year, commencing upon the date of first commercial delivery for LNG train 3; and
GAIL (India) Limited ("GAIL") has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa) for a contract sales price equal to $3.00 plus 115% of the final settlement price for the New York Mercantile Exchange Henry Hub natural gas futures contract for the month in which the relevant cargo is scheduled. The fixed portion of the contract sales price is equivalent to approximately $548 million per year, commencing upon the date of first commercial delivery for LNG train 4. Prior to the commencement of LNG train 4 operations, GAIL will purchase 10.4 million MMBtu of LNG per year (approximately 0.2 mtpa) commencing upon the date LNG train 2 becomes commercially operable.

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

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

A customer has the right to terminate its SPA if, among other events, (i) Sabine Pass Liquefaction declares an event of force majeure one or more times and the resulting interruptions total 24 or more months in any 36 month period, and such force majeure events result in a reduction of 50 percent or more in the annualized annual contract quantity of LNG available to such customer during such periods of force majeure, (ii) with respect to BG and Gas Natural Fenosa, such customer declares a force majeure event for specified circumstances and such force majeure event has continued for 24 months and has resulted in a reduction in the



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quantity of LNG that such customer is able to take of at least 50 percent of the annualized contract quantity, (iii) Sabine Pass Liquefaction fails to make available to such customer a specified number of cargoes during a 12-month period, (iv) an applicable LNG train has not commenced commercial operations at the Sabine Pass LNG terminal within 180 days after the date designated for first commercial delivery, (v) with respect to BG and Gas Natural Fenosa, Sabine Pass Liquefaction's authorizations to export LNG from the United States to either FTA or non-FTA countries has been withdrawn, revoked or expired, and such withdrawal, revocation or expiration does not constitute a force majeure, and with respect to GAIL, Sabine Pass Liquefaction's authorization to export LNG from the United States to non-FTA countries has expired, or (vi) with respect to BG and Gas Natural Fenosa, the specified limit on Sabine Pass Liquefaction's liability under the applicable SPA has been reached or exceeded.

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

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

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

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

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

In the EPC Contract, Bechtel warrants that the (i) equipment will be new (unless otherwise specified in the EPC Contract)



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

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

The EPC Contract has several termination rights:
if Bechtel fails to timely commence the work, abandons the work, fails to materially comply with its material obligations, makes an unpermitted assignment, fails to maintain required insurance, materially disregards applicable law or applicable standards and codes, or an insolvency event occurs with respect to Bechtel or its guarantor, then Sabine Pass Liquefaction will have the right to require that Bechtel cure such default, and if Bechtel fails to cure such default, or if Bechtel or its guarantor experiences an insolvency event, Sabine Pass Liquefaction may terminate the EPC Contract;
Sabine Pass Liquefaction has the right to terminate the EPC Contract for its convenience, in which case Bechtel will be paid the portion of the Contract Price for the work performed, costs reasonably incurred by Bechtel on account of such termination and demobilization, and a lump sum of between $1.0 million and $2.5 million depending on the termination date if the EPC Contract is terminated prior to issuance of the notice to proceed and up to $30.0 million depending on the termination date if the EPC Contract is terminated after issuance of the notice to proceed;
if Sabine Pass Liquefaction fails to pay any undisputed amount, fails to materially comply with any of its material obligations, or experiences an insolvency event, then Bechtel has the right to provide written notice demanding that such default be cured, and if Sabine Pass Liquefaction fails to cure such default or Sabine Pass Liquefaction experiences an insolvency event, Bechtel may terminate the EPC Contract;
if one force majeure event causes suspension of a substantial portion of the work for more than 100 consecutive days or any one or more force majeure events causes suspension of a substantial portion of the work for a period exceeding 180 days in the aggregate during any continuous 24-month period, then either party may terminate the EPC Contract; or
if Sabine Pass Liquefaction fails to issue the notice to proceed by December 31, 2012, then either party may terminate the EPC Contract, and Bechtel will be paid costs reasonably incurred by Bechtel on account of such termination and a lump sum of $5.0 million.

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

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



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LNG Terminal Competition

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

Governmental Regulation
 
The Sabine Pass LNG terminal operations are, and liquefaction project construction and operations will be, subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. This regulatory burden increases the cost of operating the Sabine Pass LNG terminal and constructing the liquefaction facilities, and failure to comply with such laws could result in substantial penalties. Through construction, commissioning and operations of our existing facilities, we have been in substantial compliance with all regulations discussed herein.
 
FERC
 
In order to site and construct the Sabine Pass LNG terminal, we received and are required to maintain authorization from the FERC under Section 3 of the Natural Gas Act of 1938, as amended ("NGA"). We will be required to obtain and maintain authorizations from the FERC to site, construct and operate liquefaction and export facilities at the Sabine Pass LNG terminal site. In addition, orders from the FERC authorizing construction of an LNG terminal are typically subject to specified conditions that must be satisfied throughout operation of the Sabine Pass LNG terminal. Throughout the life of the Sabine Pass LNG terminal, we will be subject to regular reporting requirements to the FERC and the U.S. Department of Transportation regarding the operation and maintenance of the facilities.
 
In 2005, the Energy Policy Act of 2005 ("EPAct") was signed into law. The EPAct gave the FERC exclusive authority to approve or deny an application for the siting, construction, expansion or operation of an LNG terminal. The EPAct amended the NGA to prohibit market manipulation.  The EPAct increased civil and criminal penalties for any violations of the NGA, Natural Gas Policy Act of 1978, as amended, and any rules, regulations or orders of the FERC, up to $1.0 million per day per violation. In accordance with the EPAct, the FERC issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud.
 
Other Federal Governmental Permits, Approvals and Consultations
 
In addition to the FERC authorization under Section 3 of the NGA, the operation of the Sabine Pass LNG terminal and related projects, and the construction of our proposed liquefaction facilities, are also subject to additional federal permits, orders, approvals and consultations required by other federal agencies, including: DOE, Advisory Council on Historic Preservation, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, U.S. Environmental Protection Agency ("EPA") and U.S. Department of Homeland Security.
 
The Sabine Pass LNG terminal is subject to U.S. Department of Transportation safety regulations and standards for the transportation and storage of LNG and regulations of the U.S. Coast Guard relating to maritime safety and facility security. Moreover, the Sabine Pass LNG terminal is subject to state and local laws, rules and regulations.
 
Environmental Regulation
 
The Sabine Pass LNG terminal operations, including the proposed liquefaction facilities, are subject to various federal, state and local laws and regulations relating to the protection of the environment. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial liabilities for non-compliance or releases. Failure to comply with these laws and regulations may also result in substantial civil and criminal fines and penalties.



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Clean Air Act ("CAA")
 
The Sabine Pass LNG terminal operations, including the proposed liquefaction facilities, are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing other air emission-related issues. We do not believe, however, that our operations, or the construction and operations of our proposed liquefaction facilities, will be materially and adversely affected by any such requirements.
 
The U.S. Supreme Court has ruled that the EPA has authority under existing legislation to regulate carbon dioxide and other heat-trapping gases in mobile source emissions. Mandatory reporting requirements were promulgated by the EPA and finalized in 2009. This rule requires mandatory reporting for greenhouse gases from stationary fuel combustion sources. An additional section, which requires reporting for all fugitive emissions throughout the Sabine Pass LNG terminal, was finalized in December 2010. In addition, Congress has considered proposed legislation directed at reducing "greenhouse gas emissions." It is not possible at this time to predict how future regulations or legislation may address greenhouse gas emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on our business, financial position, results of operations and cash flows.
 
Coastal Zone Management Act ("CZMA")
 
The Sabine Pass LNG terminal, including the proposed liquefaction facilities, are subject to the requirements of the CZMA throughout the construction of facilities located within the coastal zone.  The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources, and in Texas, by the Railroad Commission and the General Land Office).  This program is implemented in coordination with the Department of the Army construction permitting process to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act ("CWA")
 
The Sabine Pass LNG terminal operations are subject to the federal CWA and analogous state and local laws. Pursuant to certain requirements of the CWA, the EPA has adopted regulations concerning discharges of wastewater and storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit.
 
Resource Conservation and Recovery Act ("RCRA")
 
The federal RCRA and comparable state statutes govern the disposal of "hazardous wastes." In the event any hazardous wastes are generated in connection with the Sabine Pass LNG terminal operations, 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, including our proposed liquefaction facilities, may be restricted by requirements under the Endangered Species Act, which seeks to ensure that human activities neither jeopardize endangered or threatened animal, fish and plant species nor destroy or modify their critical habitats.

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



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Employees and Labor Relations
 
We have no employees. We rely on our general partner to manage all aspects of the operation and maintenance of the Sabine Pass LNG terminal and the conduct of our business. Because our general partner has no employees, it relies on subsidiaries of Cheniere to provide the personnel necessary to allow it to meet its management obligations to us and to Sabine Pass LNG. As of February 15, 2012, Cheniere and its subsidiaries had 232 full-time employees, including 124 employees who directly supported the Sabine Pass LNG terminal operations. See Note 13—"Related Party Transactions" in our Notes to Consolidated Financial Statements for a discussion of these arrangements.  Cheniere considers its current employee relations to be favorable.
 
Available Information

Our common units have been publicly traded since March 21, 2007, and are traded on the NYSE Amex Equities under the symbol "CQP". Our principal executive offices are located at 700 Milam Street, Suite 800, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is http://www.cheniereenergypartners.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission ("SEC") under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

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



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ITEM 1A.                      RISK FACTORS
 
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operations, financial condition, liquidity and prospects. 
The risk factors in this report are grouped into the following categories: 
Risks Relating to Our Financial Matters; 
Risks Relating to Our 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 could cause us to have inadequate liquidity and could materially and adversely affect our business, financial condition and prospects
 
As of December 31, 2011, we had $81.4 million of cash and cash equivalents and $96.1 million of restricted cash and cash equivalents, and we had $2.2 billion of total debt outstanding on a consolidated basis (before debt discounts). We incur significant interest expense relating to the assets at the Sabine Pass LNG terminal, and we anticipate needing to incur additional debt and issue equity to finance the construction of our proposed liquefaction project. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access capital markets. In addition, if we do not make a final investment decision to construct LNG trains 1 and 2 by December 31, 2012, we may not be able to refinance our existing indebtedness when it matures, including the Senior Notes. Our costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs.

In order to generate needed amounts of cash, we may sell equity or equity-related securities, including additional common units. Such sales could dilute our unitholders' proportionate indirect interests in our assets, business operations and proposed liquefaction and other projects, and could adversely affect the market price of our common units.
We have pursued and are pursuing a number of alternatives in order to generate needed amounts of cash, including potential issuances and sales of additional equity or equity-related securities by us. Such sales, in one or more transactions, could dilute our unitholders' proportionate indirect interests in our assets, business operations and proposed projects, including our proposed liquefaction project. In addition, such sales, or the anticipation of such sales, could adversely affect the market price of our common units.

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



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Each customer's contract at the Sabine Pass LNG terminal is subject to termination under certain circumstances.
 
Each of Sabine Pass LNG's long-term TUAs and Sabine Pass Liquefaction's SPAs contains various termination rights. For example, each of Sabine Pass LNG's customers may terminate its TUA if the Sabine Pass LNG terminal experiences a force majeure delay for longer than 18 months, fails to redeliver a specified amount of natural gas in accordance with the customer's redelivery nominations or fails to accept and unload a specified number of the customer's proposed LNG cargoes. Each of Sabine Pass Liquefaction's customers may terminate its SPA under the circumstances described under "Items 1. and 2. Business and Properties—Sabine Pass LNG Terminal—Liquefaction Facilities—Customers." We may not be able to replace these TUAs or SPAs on desirable terms, or at all, if they are terminated.
 
Our ability to satisfy our payment obligations is dependent upon Cheniere Marketing satisfying its obligations to us under the VCRA.
 
Under the VCRA, Cheniere Marketing is required to pay for taxes and new regulatory costs incurred under the Cheniere Investments TUA. Cheniere Marketing is also required to use commercially reasonable efforts to commercialize Cheniere Investments' TUA to the extent that neither Cheniere Marketing nor Cheniere Investments is obligated to the contrary under other agreements and to pay 80% of gross margins earned from commercial activities to Cheniere Investments. Cheniere Marketing may be obligated to make additional payments to Cheniere Investments of up to a maximum of $1.6 million per year. If Cheniere Marketing fails to make payments to Cheniere Investments under the VCRA, we may not be able to continue to make distributions, which could have a material and adverse effect on the perceived value of our partnership and the market price of our common units.

Cheniere Marketing continues to develop its business, lacks a credit rating and may also be limited by access to capital. In addition, Cheniere, which has guaranteed Cheniere Marketing's obligations under the VCRA, has a non-investment grade corporate rating of CCC+ from Standard and Poor's. Accordingly, we believe that Cheniere Marketing and Cheniere have a high risk of being financially unable to perform their obligations under the VCRA.

Risks Relating to Our Business 
Operation of the Sabine Pass LNG terminal involves significant risks.
As more fully discussed in these Risk Factors, the Sabine Pass LNG terminal faces operational risks, including the following:
performing below expected levels of efficiency;
breakdown or failures of equipment or systems;
operational errors by vessel or tug operators or others;
operational errors by us or any contracted facility operator or others;
labor disputes; and
weather-related interruptions of operations.
 
To maintain the cryogenic readiness of the Sabine Pass LNG terminal, Sabine Pass LNG may need to purchase and process LNG. Sabine Pass LNG's TUA customers have the obligation to procure LNG if necessary for the Sabine Pass LNG terminal to maintain its cryogenic state. If they fail to do so, Sabine Pass LNG may need to procure such LNG.
 
Sabine Pass LNG needs to maintain the cryogenic readiness of the Sabine Pass LNG terminal. Together with Cheniere Investments, the two third-party TUA customers have the obligation to maintain minimum inventory levels, and under certain circumstances, to procure LNG to maintain the cryogenic readiness of the terminal. In the event that aggregate minimum inventory levels are not maintained, Sabine Pass LNG has the right to procure a cryogenic readiness cargo, and to the extent that the TUA customers have failed to maintain their minimum inventory levels, be reimbursed by each TUA customer for their allocable share of the LNG acquisition costs. If Sabine Pass LNG is not able to obtain financing on acceptable terms, it will need to maintain sufficient working capital for such a purchase until it receives reimbursement for the allocable costs of the LNG from its TUA customers or sells the regasified LNG. Sabine Pass LNG may also bear the commodity price and other risks of purchasing LNG, holding it in its inventory for a period of time and selling the regasified LNG.



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Sabine Pass LNG may be required to purchase natural gas to provide fuel at the Sabine Pass LNG terminal, which would increase operating costs and could have a material adverse effect on our results of operations.
 
Sabine Pass LNG's TUAs provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG terminal, which it uses primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. There is a risk that this 2% in-kind deduction will be insufficient for these needs and that Sabine Pass LNG will have to purchase additional natural gas from third parties. Sabine Pass LNG will bear the cost and risk of changing prices for any such fuel.
 
Hurricanes or other disasters could adversely affect us.
 
In August and September of 2005, Hurricanes Katrina and Rita damaged coastal and inland areas located in Texas, Louisiana, Mississippi and Alabama. Construction at the Sabine Pass LNG terminal site was temporarily suspended in connection with Hurricane Katrina, as a precautionary measure. Approximately three weeks after the occurrence of Hurricane Katrina, the Sabine Pass LNG terminal site was again secured and evacuated in anticipation of Hurricane Rita, the eye of which made landfall to the east of the site. As a result of these 2005 storms and related matters, the Sabine Pass LNG terminal experienced construction delays and increased costs. In September 2008, Hurricane Ike struck the Texas and Louisiana coast, and the Sabine Pass LNG terminal experienced damage.
 
Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal or related infrastructure, as well as delays or cost increases in the construction of our proposed liquefaction facilities. If there are changes in the global climate, storm frequency and intensity may increase; should it result in rising seas, our coastal operations would be impacted.
 
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development, construction and operation of the Sabine Pass LNG terminal could impede operations and construction and could have a material adverse effect on us.
 
The operation of the Sabine Pass LNG terminal and the design, construction and operation of our proposed liquefaction facilities, and the import and export of LNG, are highly regulated activities. The FERC's approval under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to operate the Sabine Pass LNG terminal and to construct and operate liquefaction facilities. Although we have obtained all of the necessary authorizations to operate the Sabine Pass LNG terminal, Sabine Pass Liquefaction will need authorization from the FERC to construct and operate our proposed liquefaction facilities. Such authorizations are subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 
The construction of our project to add liquefaction capacity at the Sabine Pass LNG terminal will be subject to a number of development risks, which could cause cost increases and delays or prevent completion of the project.
 
Key factors that may affect the timing of, and our ability to complete, the project at the Sabine Pass LNG terminal to add liquefaction capacity include, but are not limited to:

the issuance and/or continued availability of necessary permits, licenses and approvals from governmental agencies and third parties as are required to construct and operate liquefaction facilities;
the availability of sufficient financing on reasonable terms, or at all;
our ability to satisfy the conditions precedent in SPAs with customers by specified dates;
our ability to meet the conditions precedent in our construction contract with Bechtel by December 31, 2012 in order to commence construction of the first two LNG trains;
our ability to enter into additional satisfactory agreements with contractors and to maintain good relationships with these contractors in order to construct the proposed liquefaction facilities within the expected cost parameters, and the ability of those contractors to perform their obligations under the contracts and to maintain their creditworthiness;
local and general economic conditions;



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catastrophes, such as explosions, fires and product spills;
resistance in the local community to the project to add liquefaction capabilities at the Sabine Pass LNG terminal;
labor disputes; and
weather conditions, such as hurricanes.
 
Delays in the construction of the proposed liquefaction facilities at the Sabine Pass LNG terminal beyond the estimated development periods, as well as change orders to the EPC contract with Bechtel, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until the proposed liquefaction facilities are constructed (which could cause further delays). Any delay in completion of the proposed liquefaction facilities may also cause a delay in the receipt of revenues projected therefrom or cause a loss of one or more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 
We are entirely dependent on Cheniere, including employees of Cheniere and its subsidiaries, for key personnel, and a loss of key personnel could have a material adverse effect on our business.
 
As of February 15, 2012, Cheniere and its subsidiaries had 232 full-time employees, including 124 employees who directly supported the Sabine Pass LNG terminal operations. We have contracted with subsidiaries of Cheniere to provide the personnel necessary for the operation, maintenance and management of the Sabine Pass LNG terminal. We face competition for these highly skilled employees in the immediate vicinity of the Sabine Pass LNG terminal and more generally from the Gulf Coast hydrocarbon processing and construction industries.
 
Our general partner's executive officers are officers and employees of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel, and our general partner does not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could have a material adverse effect on our business. In addition, our future success will depend in part on our general partner's ability to engage, and Cheniere's ability to attract and retain, additional qualified personnel.
 
We have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.
 
We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, Cheniere Investments has entered into a Variable Capacity Rights Agreement with Cheniere Marketing, under which Cheniere Marketing will be able to derive economic benefits to the extent it assists Cheniere Investments in commercializing Cheniere Investments' TUA with Sabine Pass LNG. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand.
 
We are dependent on Cheniere and its affiliates to provide services to us. If Cheniere or its affiliates are unable or unwilling to perform according to the negotiated terms and timetable of their respective agreement for any reason or terminates their agreement, we would be required to engage a substitute service provider. This could result in a significant interference with operations and increased costs.
 
We may not be successful in implementing our proposed business strategy to provide liquefaction capabilities at the Sabine Pass LNG terminal.
 
A significant element of our strategy to monetize our reserved capacity at the Sabine Pass LNG terminal is to develop liquefaction facilities at the terminal, construction of which has not yet commenced. Our proposed liquefaction facilities will require very significant financial resources, which may not be available on terms reasonably acceptable to us or at all. Our contract with Bechtel to construct the first two LNG trains requires that we secure financing in the amount of the contract price by March 31, 2012 or Bechtel has the right to submit change orders, which may result in higher costs. Our SPAs with BG, Gas Natural Fenosa, GAIL and KOGAS also contain certain conditions precedent, including, but not limited to, receiving regulatory approvals, securing necessary financing arrangements and making a final investment decision to construct the liquefaction facilities. If these conditions are not met by December 31, 2012 with respect to BG (for LNG train 1) and Gas Natural Fenosa and June 30, 2013 with respect to GAIL and KOGAS, either party may terminate the contract. In addition, if Sabine Pass Liquefaction has not made a positive



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final investment decision regarding the Train 2 Tranche, the Train 3 Tranche or the Train 4 Tranche by June 30, 2013, then BG may cancel such tranche(s) that are not yet decided affirmatively. If we are unable to obtain adequate and timely financing on satisfactory terms, Bechtel, BG, Gas Natural Fenosa, GAIL and KOGAS may terminate their respective contracts with us, and we may not be able to enter into contracts with another contractor or customer on similar terms or at all.

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

The cost of constructing our proposed liquefaction facilities will be dependent on several items, including change orders. As a result, if completed, the actual construction cost of these facilities may be significantly higher than our current estimates, which are before financing costs and contingencies.
 
As construction progresses, we may decide or be forced to submit change orders to Bechtel that could result in a longer construction period and higher construction costs. Our contract with Bechtel to construct the first two LNG trains requires that we secure financing in the amount of the contract price by March 31, 2012 or Bechtel has the right to submit change orders, which may result in higher costs. As a result, any significant change orders or increases in commodity prices could increase our anticipated costs and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

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

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

design and engineer our proposed LNG liquefaction facilities to operate in accordance with specifications;
engage and retain third-party subcontractors and procure equipment and supplies;
respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;
attract, develop and retain skilled personnel, including engineers;
post required construction bonds and comply with the terms thereof;
manage the construction process generally, including coordinating with other contractors and regulatory agencies; and
maintain their own financial condition, including adequate working capital.
 
Although some contracts may provide for liquidated damages, if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable LNG liquefaction facility, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the project or result in a contractor's unwillingness to perform further work on the project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 



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

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

Our use of hedging arrangements may adversely affect our future results of operations or liquidity.
To reduce our exposure to fluctuations in the price, volume and timing risk associated with the marketing of LNG and natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange ("ICE") and NYMEX, or over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when:
expected supply is less than the amount hedged;
the counterparty to the hedging contract defaults on its contractual obligations; or
there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
 
Our hedging arrangements may also limit the benefit that we would receive from increases in the prices for natural gas. The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

Decreases in the demand for and price of natural gas could lead to reduced development of LNG projects worldwide, which could adversely affect the regasification component of our business and the performance of our TUA customers and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 
The development of domestic LNG facilities and LNG projects generally is based on assumptions about the future price of natural gas and the availability of natural gas. Natural gas prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:
relatively minor changes in the supply of, and demand for, natural gas in relevant markets;
political conditions in natural gas producing regions;
the extent of domestic production and importation of natural gas in relevant markets;
the level of demand for LNG and natural gas in relevant markets, including the effects of economic downturns or upturns;
weather conditions;
the competitive position of natural gas as a source of energy compared with other energy sources; and
the effect of government regulation on the production, transportation and sale of natural gas.
 
Adverse trends or developments affecting any of these factors could result in decreases in the price of natural gas, leading to reduced development of LNG projects worldwide. Such reductions could adversely affect the regasification component of our business and the performance of our TUA customers and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 



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Cyclical or other changes in the demand for LNG capacity may adversely affect our business and the performance of our customers and could reduce our operating revenues and may cause us operating losses.
 
The economics of the Sabine Pass LNG terminal could be subject to cyclical swings, reflecting alternating periods of under-supply and over-supply of LNG import or export capacity and available natural gas, principally due to the combined impact of several factors, including:
additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG from the Sabine Pass LNG terminal;
competitive liquefaction capacity in North America, which could divert natural gas from our proposed liquefaction facilities at the Sabine Pass LNG terminal;
insufficient or oversupply of LNG liquefaction or receiving capacity worldwide;
insufficient LNG tanker capacity;
reduced demand and lower prices for natural gas;
increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
cost improvements that allow competitors to offer LNG regasification services or provide liquefaction capabilities at reduced prices;
changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;
adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and
cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
 
These factors could materially and adversely affect our ability, and the ability of our current and prospective customers, to procure supplies of LNG to be imported into North America and to procure customers for LNG or regasified LNG at economical prices, or at all. In addition, these factors may result in fewer LNG assets being constructed or available for acquisition by us at any given time and, therefore, limit our ability to increase distributions to unitholders.
 
Various economic and political factors could negatively affect the continued development of LNG facilities, including Cheniere Partners' proposed liquefaction facilities which could adversely affect our LNG business and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 
Commercial development of an LNG facility takes a number of years, requires a substantial capital investment and may be delayed by factors such as:
increased construction costs;
economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;
decreases in the price of LNG and natural gas, which might decrease the expected returns relating to investments in LNG projects;
the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;
political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and
any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.
 



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There may be shortages of LNG vessels worldwide, which could adversely affect our LNG business and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 
The construction and delivery of LNG vessels require significant capital and long construction lead times, and the availability of the vessels could be delayed to the detriment of our LNG 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.
 
Terrorist attacks or military campaigns may adversely impact our business.
 
A terrorist or military incident involving an LNG facility or LNG carrier may result in delays in, or cancellation of, construction of new LNG facilities, including our proposed liquefaction facilities, which would increase our costs and decrease our cash flows. A terrorist incident may also result in temporary or permanent closure of existing LNG facilities, including the Sabine Pass LNG terminal, which could increase our costs and decrease our cash flows, depending on the duration of the closure. Operations at the Sabine Pass LNG terminal could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our LNG business and our customers, including their ability to satisfy their obligations to us under the commercial agreements.

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

The construction and operation of the Sabine Pass LNG terminal, including our proposed liquefaction facilities, are and will be subject to the inherent risks associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.
 
We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 
Existing and future environmental and similar laws and regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.
 
Our business is and will be subject to extensive federal, state and local laws and regulations that control, among other things, discharges to air and water; the handling, storage and disposal of hazardous chemicals, hazardous waste, and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of the Sabine Pass LNG terminal, including liquefaction facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. Violation of these laws and regulations could lead to substantial fines and penalties or to capital expenditures related to pollution control equipment that could have a material adverse



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effect on our business, results of operations, financial condition, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of an LNG terminal, including a liquefaction facility, we could be liable for the costs of cleaning up hazardous substances released into the environment and for damage to natural resources.

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

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

We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain key personnel could adversely affect us.
 
We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to operate the Sabine Pass LNG terminal, to construct and operate liquefaction facilities and to provide our customers with the highest quality service. Our affiliates who hire personnel on our behalf are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. For example, in the aftermaths of Hurricanes Katrina and Rita, Bechtel and certain subcontractors temporarily experienced a shortage of available skilled labor necessary to meet the requirements of the Sabine Pass LNG terminal construction plan. As a result, we agreed to change orders with Bechtel concerning additional activities and expenditures to mitigate the hurricanes' effects on the construction of the Sabine Pass LNG terminal. Any increase in our operating costs could materially and adversely affect our business, results of operations, financial condition, liquidity and prospects.
 
Our lack of diversification could have an adverse effect on our financial condition and results of operations.
 
Substantially all of our anticipated revenue in 2012 will be dependent upon one facility, the Sabine Pass LNG terminal in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass LNG terminal, or in the LNG industry, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.
 
If we do not make acquisitions or implement capital expansion projects on economically acceptable terms, our future growth and our ability to increase distributions to our unitholders will be limited.
 
Our ability to grow depends on our ability to make accretive acquisitions or implement accretive capital expansion projects, such as our proposed liquefaction facilities. We may be unable to make accretive acquisitions or implement accretive capital expansion projects for any of the following reasons:
we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
we are unable to identify attractive capital expansion projects or negotiate acceptable engineering procurement and construction arrangements for them;
we are unable to obtain necessary governmental approvals;



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we are unable to obtain financing for the acquisitions or capital expansion projects on economically acceptable terms, or at all;
we are unable to secure adequate customer commitments to use the acquired or expansion facilities; or
we are outbid by competitors.
 
If we are unable to make accretive acquisitions or implement accretive capital expansion projects, then our future growth and ability to increase distributions to our unitholders will be limited.

We intend to pursue acquisitions of additional LNG terminals, natural gas pipelines and related assets in the future, either directly from Cheniere or from third parties. However, Cheniere is not obligated to offer us any of these assets. If Cheniere does offer us the opportunity to purchase assets, we may not be able to successfully negotiate a purchase and sale agreement and related agreements, we may not be able to obtain any required financing for such purchase and we may not be able to obtain any required governmental and third-party consents. The decision whether or not to accept such offer, and to negotiate the terms of such offer, will be made by the conflicts committee of our general partner, which may decline the opportunity to accept such offer for a variety of reasons, including a determination that the acquisition of the assets at the proposed purchase price would not result in an increase, or a sufficient increase, in our adjusted operating surplus per unit within an appropriate timeframe.
 
If we make acquisitions, they could adversely affect our business and ability to make distributions to our unitholders.
 
If we make any acquisitions, they will involve potential risks, including:
an inability to integrate successfully the businesses that we acquire with our existing business;
a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the acquisition;
the assumption of unknown liabilities;
limitations on rights to indemnity from the seller;
mistaken assumptions about the cash generated, or to be generated, by the business acquired or the overall costs of equity or debt;
the diversion of management's and employees' attention from other business concerns; and
unforeseen difficulties encountered in operating new business segments or in new geographic areas.
 
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our future funds and other resources. In addition, if we issue additional units in connection with future growth, our existing unitholders' interest in us will be diluted, and distributions to our unitholders may be reduced. 

Risks Relating to Our Cash Distributions
 
We will need to refinance, extend or otherwise satisfy our substantial indebtedness, and principal amortization or other terms of our future indebtedness could limit our ability to pay or increase distributions to our unitholders.
 
We will need to refinance, extend or otherwise satisfy $550.0 million of Senior Notes that mature in 2013 and $1,666.0 million of Senior Notes that mature in 2016 (together, the "Senior Notes"). We are not generally required to make principal payments on the Senior Notes prior to maturity. Our ability to refinance, extend or otherwise satisfy the Senior Notes, and the principal amortization, interest rate and other terms on which we may be able to do so, will depend among other things on our then contracted or otherwise anticipated future cash flows available for debt service. Our TUAs with Total and Chevron, which provide substantially all of our current operating cash flows, will expire in 2029 unless extended. Our ability to pay or increase distributions to our unitholders in future years could be limited by principal amortization, interest rate or other terms of our future indebtedness.




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Sabine Pass LNG may be restricted under the terms of the Sabine Pass Indenture from making distributions under certain circumstances, which may limit our ability to pay or increase distributions to our unitholders.
 
The Sabine Pass Indenture restricts payments that Sabine Pass LNG can make to us in certain events and limits the indebtedness that Sabine Pass LNG can incur. Sabine Pass LNG is permitted to pay distributions to us only after the following payments have been made:
an operating account has been funded with amounts sufficient to cover the succeeding 45 days of operating and maintenance expenses, maintenance capital expenditures and obligations, if any, under an assumption agreement and a state tax sharing agreement;
one-sixth of the amount of interest due on the Senior Notes on the next interest payment date (plus any shortfall from any such month subsequent to the preceding interest payment date) has been transferred to a debt payment account;
outstanding principal on the Senior Notes then due and payable has been paid;
taxes payable by Sabine Pass LNG or the guarantors of the Senior Notes and permitted payments in respect of taxes have been paid; and
the debt service reserve account has on deposit the amount required to make the next interest payment on the Senior Notes.
 
In addition, Sabine Pass LNG will only be able to make distributions to us in the event that it could, among other things, incur at least $1.00 of additional indebtedness under the fixed charge coverage ratio test of 2:1 at the time of payment and after giving pro forma effect to the distribution. Sabine Pass LNG is also prohibited under the Sabine Pass Indenture from paying distributions to us or incurring additional indebtedness upon the occurrence of any of the following events, among others:
a default for 30 days in the payment of interest on, or additional interest, if any, with respect to, the Senior Notes;
a failure to pay any principal on the Senior Notes;
a failure by Sabine Pass LNG to comply with various covenants in the Sabine Pass Indenture;
a failure to observe any other agreement in the Sabine Pass Indenture beyond any specified cure periods;
a default under any mortgage, indenture or instrument governing any indebtedness for borrowed money by Sabine Pass LNG in excess of $25.0 million if such default results from a failure to pay principal or interest on, or results in the acceleration of, such indebtedness;
a final money judgment or decree (not covered by insurance) in excess of $25.0 million is not discharged or stayed within 60 days following entry;
a failure of any material representation or warranty in the security documents entered into in connection with the indenture to be correct;
the Sabine Pass LNG terminal project is abandoned; or
certain events of bankruptcy or insolvency.
 
Sabine Pass LNG's inability to pay distributions to us or to incur additional indebtedness as a result of the foregoing restrictions in the Sabine Pass Indenture may inhibit our ability to pay or increase distributions to our unitholders.
 
The fixed charge coverage ratio test contained in the Sabine Pass Indenture could prevent Sabine Pass LNG from making cash distributions. As a result, we may be prevented from making distributions to our unitholders, which could materially and adversely affect the market price of our common units.
 
Sabine Pass LNG is not permitted to make cash distributions if its consolidated cash flow is not at least twice its fixed charges, calculated as required in the Sabine Pass Indenture. In order to satisfy this fixed charge coverage ratio test, we estimate that Sabine Pass LNG's consolidated cash flow, as defined in the Sabine Pass Indenture, must be greater than approximately $375 million. Thus, TUA payments from Cheniere Investments are needed in addition to the TUA payments from Chevron and Total.
 



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

Our ability to pay cash distributions on our units could be limited if Cheniere Marketing fails to make payments to Cheniere Investments under the VCRA, if Cheniere Investments fails to make payments to Sabine Pass LNG under its TUA, or if Sabine Pass LNG fails to make cash distributions.
 
Under the VCRA, Cheniere Marketing is required to pay for taxes and new regulatory costs incurred under the Cheniere Investments TUA. Cheniere Marketing is also required to use commercially reasonable efforts to commercialize Cheniere Investments' TUA to the extent that neither Cheniere Marketing nor Cheniere Investments is obligated to the contrary under other agreements and to pay 80% of gross margins earned from commercial activities to Cheniere Investments. Cheniere Marketing is obligated to make minimum payments to Cheniere Investments of up to a maximum of $1.6 million per year. If Cheniere Marketing fails to make payments to Cheniere Investments under the VCRA, we may not be able to continue to make distributions to our unitholders, which could have a material and adverse effect on the perceived value of our partnership and the market price of our common units.

The Sabine Pass Indenture may prevent Sabine Pass LNG from engaging in certain beneficial transactions.
 
In addition to restrictions on the ability of Sabine Pass LNG to make distributions or incur additional indebtedness, the Sabine Pass Indenture also contains various other covenants that may prevent it from engaging in beneficial transactions, including limitations on the ability of Sabine Pass LNG or certain of its subsidiaries to:
make certain investments;
purchase, redeem or retire equity interests;
issue preferred stock;
sell or transfer assets;
incur liens;
enter into transactions with affiliates;
consolidate, merge, sell or lease all or substantially all of its assets; and
enter into sale and leaseback transactions.
 
Management fees and cost reimbursements due to our general partner and its affiliates will reduce cash available to pay distributions to our unitholders.
We pay significant management fees to our general partner and its affiliates and reimburse them for expenses incurred on our behalf, which reduces our cash available for distribution to our unitholders. These fees and expenses are payable as follows:
under a services agreement, we pay an affiliate of Cheniere a variable administrative fee for general and administrative services for our benefit not to exceed $2.5 million per quarter (indexed for inflation). This fee does not include reimbursements by us of direct expenses that the affiliate incurs on our behalf, such as salaries of operational personnel performing services on-site at the Sabine Pass LNG terminal and the cost of their employee benefits, including 401(k) plan, pension and health insurance benefits;
under an operation and maintenance agreement with an affiliate of Cheniere, Sabine Pass LNG pays a fixed monthly fee of $130,000 (indexed for inflation) and reimburses our general partner for its operating expenses, which consist primarily of labor expenses. Cheniere's affiliate, under certain circumstances, will be entitled to a bonus equal to 50% of the salary component of labor costs;
under a management services agreement with an affiliate of Cheniere, Sabine Pass LNG pays a fixed monthly fee of $520,000 (indexed for inflation); and



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we estimate that our partnership will incur costs of approximately $2.5 million per year, adjusted for inflation at 2½% per year, for tax compliance and publicly traded partnership tax reporting, accounting, SEC reporting and other costs of operating as a publicly traded partnership.
 
Our general partner and its affiliates will also be entitled to reimbursement for all other direct expenses that they incur on our behalf. The payment of fees to our general partner and its affiliates and the reimbursement of expenses could adversely affect our ability to pay cash distributions to our unitholders.
 
The amount of cash that we have available for distributions to our unitholders will depend primarily on our cash flow and not solely on profitability.
 
The amount of cash that we will have available for distributions will depend primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.
As a result of the assignment of the Cheniere Marketing TUA to Cheniere Investments in June 2010, our available cash for distributions was reduced. Therefore, we have not paid any distributions on our subordinated units with respect to the quarters ended on or after June 30, 2010.  We may not have sufficient cash available for distributions on our subordinated units in the future. Any further reduction in the amount of cash available for distributions could impact our ability to pay the initial quarterly distribution on our common units in full or at all.
 
We may not be able to maintain or increase the distributions on our common units unless we are able to commercialize the Cheniere Investments TUA, make accretive acquisitions or implement accretive capital expansion projects, which may require us to obtain one or more sources of funding.
 
We may not successfully commercialize the Cheniere Investments TUA and we may not be able to make accretive acquisitions or implement accretive capital expansion projects, including our proposed liquefaction facilities, that would result in sufficient cash flow to fully pay distributions to the subordinated unitholders and allow us to increase common unitholder distributions. To fund acquisitions or capital expansion projects, we will need to pursue a variety of sources of funding, including debt and/or equity financings. Our ability to obtain these or other types of financing will depend, in part, on factors beyond our control, such as our ability to obtain commitments from users of the facilities to be acquired or constructed, the status of various debt and equity markets at the time financing is sought and such markets' view of our industry and prospects at such time. Any restrictive lending conditions in the U.S. credit markets may make it more time consuming and expensive for us to obtain financing, if we can obtain such financing at all. Accordingly, we may not be able to obtain financing for acquisitions or capital expansion projects on terms that are acceptable to us, if at all.
 
Agreements with counterparties located outside the United States could expose us to political, governmental and economic instability and effects of foreign currency exchange rate fluctuations on our counterparties.
 
Agreements with counterparties located outside of the United States could cause us to be affected by economic, political and governmental conditions in the countries where those counterparties are located. Any disruption caused by these factors could harm our business. Risks associated with agreements with counterparties located outside of the United States include the risks of:
currency fluctuations affecting our counterparties;
war;
expropriation or nationalization of assets of our counterparties;
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 our counterparties' operations are conducted.



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Risks Relating to an Investment in Us and Our Common Units
 
Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of us and our unitholders.
 
Cheniere controls our general partner, which has sole responsibility for conducting our business and managing our operations. Some of our general partner's directors are also directors of Cheniere, and certain of our general partner's officers are officers of Cheniere. Therefore, conflicts of interest may arise between Cheniere and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of us and our unitholders. These conflicts include, among others, the following situations:
neither our partnership agreement nor any other agreement requires Cheniere to pursue a business strategy that favors us. Cheniere's directors and officers have a fiduciary duty to make these decisions in favor of the owners of Cheniere, which may be contrary to our interests:
our general partner controls the interpretation and enforcement of contractual obligations between us, on the one hand, and Cheniere, on the other hand, including provisions governing administrative services and acquisitions;
our general partner is allowed to take into account the interests of parties other than us, such as Cheniere and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us and our unitholders;
our general partner has limited its liability and reduced its fiduciary duties under the partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty;
Cheniere is not limited in its ability to compete with us. Please read “-Cheniere is not restricted from competing with us and is free to develop, operate and dispose of, and is currently developing, LNG terminals, pipelines and other assets without any obligation to offer us the opportunity to develop or acquire those assets”;
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities, and the establishment, increase or decrease in the amounts of reserves, each of which can affect the amount of cash that is distributed to our unitholders;
our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;
our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; and
our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
We expect that there will be additional agreements or arrangements with Cheniere and its affiliates, including future interconnection, natural gas balancing and storage agreements with one or more Cheniere-affiliated natural gas pipelines, services agreements, as well as other agreements and arrangements that cannot now be anticipated. In those circumstances where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.




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Cheniere is not restricted from competing with us and is free to develop, operate and dispose of, and is currently developing, LNG terminals, pipelines and other assets without any obligation to offer us the opportunity to develop or acquire those assets.
 
Cheniere and its affiliates are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. Cheniere may acquire, construct or dispose of its proposed Corpus Christi or Creole Trail LNG terminals, its proposed pipelines or any other assets without any obligation to offer us the opportunity to purchase or construct any of those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to Cheniere and its affiliates. As a result, neither Cheniere nor any of its affiliates will have any obligation to present new business opportunities to us, and they may take advantage of such opportunities themselves. Cheniere also has significantly greater resources and experience than we have, which may make it more difficult for us to compete with Cheniere and its affiliates with respect to commercial activities or acquisition candidates.
 
Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner, as long as it acted in good faith, meaning that it believed the decision was in the best interests of our partnership;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us;
provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was criminal; and
provides that in resolving conflicts of interest, it will be presumed that in making its decision the conflicts committee or the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
 
By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.
 
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units trade.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen entirely by Holdings. As a result, the price at which the common units will trade could be diminished because of the absence or reduction of a control premium in the trading price.




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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 Cheniere Subsidiary Holdings, LLC, an affiliate of Cheniere, because Cheniere Subsidiary Holdings owns a sufficient number of subordinated units to be able to prevent removal of our general partner. The vote of the holders of at least 66 2/3% of all outstanding common and subordinated units (including any units owned by our general partner and its affiliates) voting together as a single class is required to remove our general partner. Cheniere Subsidiary Holdings owns approximately 86.8% of our outstanding common and subordinated units. In addition, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of poor management of the business, so the removal of the general partner because of the unitholder's dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.
 
Control of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.
 
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
 
An affiliate of our general partner owns 39% of our total common units. If the subordinated units convert into common units, affiliates of our general partner will own approximately 89% of the common units. If at any time more than 80% of our outstanding common units are owned by our general partner and its affiliates, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of our common units held by unaffiliated persons at a price not less than their then-current market price, as defined in our partnership agreement. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of our common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units or other equity securities and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the common units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.
 
Our partnership agreement restricts the voting rights of unitholders (other than our general partner and its affiliates) owning 20% or more of any class of our units.
 
Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.




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Our partnership agreement prohibits a unitholder (other than our general partner and its affiliates) who acquires 15% or more of our limited partner units without the approval of our general partner from engaging in a business combination with us for three years unless certain approvals are obtained. This provision could discourage a change of control that our unitholders may favor, which could negatively affect the price of our common units.
 
Our partnership agreement effectively adopts Section 203 of the Delaware General Corporation Law ("DGCL"). Section 203 of the DGCL as it applies to us prevents an interested unitholder-defined as a person (other than our general partner and its affiliates) who owns 15% or more of our outstanding limited partner units-from engaging in business combinations with us for three years following the time such person becomes an interested unitholder unless certain approvals are obtained. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. This provision of our partnership agreement could have an anti-takeover effect with respect to transactions not approved in advance by our general partner, including discouraging takeover attempts that might result in a premium over the market price for our common units.
 
Our unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for contractual obligations of the partnership that are expressly made without recourse to the general partner. We are organized under Delaware law, and we conduct business in other states. As a limited partner in a partnership organized under Delaware law, holders of our common units could be held liable for our obligations to the same extent as a general partner if a court determined that the right or the exercise of the right by our unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under our partnership agreement constituted participation in the “control” of our business. In addition, limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions.
 
Our unitholders may have liability to repay distributions wrongfully made.
 
Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that, for a period of three years from the date of the impermissible distribution, partners who received such a distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partner interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
 
We may issue additional units without approval of our unitholders, which would dilute their ownership interest.
 
At any time during the subordination period, with the approval of the conflicts committee of the board of directors of our general partner, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. After the subordination period, we may issue an unlimited number of limited partner interests of any type without limitation of any kind. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
our unitholders' proportionate ownership interest in us will decrease;
the amount of cash available per unit to pay distributions may decrease;
because a lower percentage of total outstanding units will be subordinated units, the risk will increase that a shortfall in the payment of the initial quarterly distributions will be borne by our common unitholders;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.
 



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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 common units or subordinated units, which sales could have an adverse impact on the trading price of the common units.
 
Sales by us or any of our affiliated unitholders of a substantial number of our common units or our subordinated units, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. Affiliates of Cheniere own 11,963,488 common units and 135,383,831 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier. Any sales of these units could have an adverse impact on the price of the common units.

Risks Relating to Tax Matters
 
Our tax treatment depends on our status as a partnership for federal income tax purposes. If we were treated as a corporation for federal income tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this matter.
 
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distributions to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
 
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
 



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If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to you.
 
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we will be required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas, if any, in the prior year. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
 
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
 
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time.  Any modification to the U.S. federal income tax laws and interpretations thereof could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, or Qualifying Income Exception, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units.  For example, the Obama administration and members of Congress have recently considered substantive changes to the existing federal income tax laws that would adversely affect the tax treatment of certain publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively.  We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted.  Any such changes could negatively impact the value of an investment in our common units and the amount of cash available for distribution to our unitholders.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular unit is transferred.  The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method.  Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Moreover, the proposed regulations did not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
 
A change in tax treatment of our partnership, or a successful IRS contest of the federal income tax positions that we take, may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.
 
The IRS may adopt positions that differ from the positions that we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions that we take. A court may not agree with some or all of the positions that we take. Any contest with the IRS may adversely impact the taxable income reported to our unitholders and the income taxes they are required to pay. As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. 




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Our unitholders may be required to pay taxes on their share of our taxable income even if they do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in amount from the cash that we distribute, our unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability which results from their share of our taxable income.
 
We intend to allocate items of income, gain, loss and deduction among the holders of our common units and subordinated units on or after the date that the subordination period ends to ensure that common units issued in exchange for our subordinated units have the same economic and federal income tax characteristics as our other common units. Any such allocation of items of our income or gain to unitholders, which may include allocations to holders of our common units, would not be accompanied by a distribution of cash to such unitholders. In addition, any such allocation of items of deduction or loss to specific unitholders (for example, to the holder of the subordinated units) would effectively reduce the amount of items of deduction or loss that will be allocated to other unitholders.
 
Tax gain or loss on the disposition of our common units could be different than expected.
 
If our unitholders sell common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income a unitholder is allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to them if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to our unitholders. In addition, because the amount realized may include a unitholder's share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.
 
Tax-exempt entities face unique tax issues from owning common units that may result in adverse tax consequences to them.
 
Investments in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them.
 
Non-U.S. investors face unique tax issues from owning common units that may result in adverse tax consequences to them.
 
Non-U.S. investors who own common units will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Distributions to non-U.S. investors will generally be reduced by withholding taxes at the highest applicable effective tax rate (currently 35%) whether or not we have taxable income. The IRS has taken the position that a non-U.S. investor's gain on the sale of common units is subject to United States federal income tax.
 
We will treat each holder of our common units as having the same tax benefits without regard to the actual common units held. The IRS may challenge this treatment, which could adversely affect the value of our common units.
 
Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of applicable Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the common unitholders' tax returns.
  
Our unitholders will likely be subject to state and local taxes and return filing requirements as a result of an investment in our common units.
 
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in



30



which we do business or own property, even if the unitholder does not live in any of those jurisdictions. Our unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Furthermore, our unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own property or conduct business in additional states or foreign countries that impose a personal tax or an entity level tax. It is the responsibility of our unitholders to file all United States federal, state and local tax returns.
 
The sale or exchange of 50% or more of the total interest in our capital and profits during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if special relief from the IRS was not available) for one fiscal year. Our technical termination could also result in a deferral of depreciation deductions allowable in computing our taxable income.
 
In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in the unitholder's taxable income for the year of termination. Our technical termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership, we would be required to make new tax elections and we could be subject to penalties if we are unable to determine that a technical termination occurred.
 
We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders.  The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner.  Our methodology may be viewed as understating the value of our assets.  In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders.  Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets.  The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders.  It also could affect the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
 
A unitholder whose common units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
 
Because a unitholder whose common units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.  Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.  Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.




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 ITEM 1B.    UNRESOLVED STAFF COMMENTS
 
None.
 
ITEM 3.     LEGAL PROCEEDINGS
 
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2011, there were no threatened or pending legal matters that would have a material impact on our consolidated results of operations, financial position or cash flows.
 
ITEM 4.     MINE SAFETY DISCLOSURE
  
None.
PART II
 
ITEM 5.     MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
 
Our common units began trading on the NYSE Amex Equities under the symbol "CQP" commencing with our initial public offering on March 21, 2007. The table below presents the high and low daily closing sales prices per common unit, as reported by the NYSE Amex Equities, and cash distributions to common unitholders for the period indicated.
 
 
High
 
Low
 
Cash Distributions Per Common Unit (1)
 
Cash Distributions
Per Subordinated Unit (2)
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

 

 
 
 
 
 
 
 
 
 
Three Months Ended
 
 

 
 

 
 

 
 

March 31, 2010
 
16.38

 
13.28

 
0.425

 
0.425

June 30, 2010
 
19.1

 
14.14

 
0.425

 

September 30, 2010
 
19.09

 
16.16

 
0.425

 

December 31, 2010
 
21.31

 
18.69

 
0.425

 

 
(1)
We also paid cash distributions to our general partner with respect to its 2% general partner interest.
(2)
As a result of the assignment of Cheniere Marketing's TUA to Cheniere Investments, effective July 1, 2010, our available cash for distributions was reduced. Therefore, we did not pay any distributions on our subordinated units with respect to the quarters ended on or after June 30, 2010.
 
A distribution for the quarter ended December 31, 2011 of $0.425 per common unit was paid on February 14, 2012. In addition, we paid cash distributions to our general partner with respect to its 2% general partner interest.
 
As of February 15, 2012, we had 31,003,154 common units outstanding held by approximately 10 record owners.
 
We consider cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. The Sabine Pass Indenture described in "Management’s Discussion and Analysis of Financial Condition and Results of Operations" may prohibit Sabine Pass LNG from making cash distributions to us under certain circumstances, which could limit our ability to make distributions.
 



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Upon the closing of our initial public offering, Cheniere received 135,383,831 subordinated units. Below is a description of our cash distribution policy regarding common and subordinated units.
 
Cash Distribution Policy

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

Subordination Period
 
During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the initial quarterly distribution of $0.425 per quarter, plus any arrearages in the payment of the initial quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Cheniere Subsidiary Holdings, LLC owns all of the 135,383,831 subordinated units, representing 81.4% of the limited partner interests in us. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until after the common units have received the initial quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordination period is to increase the likelihood that during this period there will be sufficient available cash to pay the initial quarterly distribution on the common units.
 
As a result of the assignment of Cheniere Marketing's TUA to Cheniere Investments, effective July 1, 2010, our available cash for distributions was reduced. Therefore, we have not paid distributions on our subordinated units since the distribution made with respect to the quarter ended March 31, 2010.
 
Definition of Subordination Period  
The subordination period will extend until the first business day following the distribution of available cash to partners in respect of any quarter that each of the following occurs: 
distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the initial quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
the "adjusted operating surplus" (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the initial quarterly distributions on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and
there are no arrearages in payment of the initial quarterly distribution on the common units.
 
Expiration of the Subordination Period  
When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:  
the subordination period will end and each subordinated unit will immediately convert into one common unit;
any existing arrearages in payment of the initial quarterly distribution on the common units will be extinguished; and
the general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests.
 



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Early Conversion of Subordinated Units  
The subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis on the first business day following the distribution of available cash to partners in respect of any quarter that each of the following occurs: 
distributions of available cash from operating surplus on each outstanding common unit, subordinated unit and general partner unit equaled or exceeded $2.55 (150% of the annualized initial quarterly distribution) for the four-quarter period immediately preceding that date;
the "adjusted operating surplus" (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.55 (150% of the annualized initial quarterly distribution) on all of the outstanding common units, subordinated units and general partner units on a fully diluted basis; and
there are no arrearages in payment of the initial quarterly distribution on the common units.
 
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 (other than amounts released from the distribution reserve); less
any net increase in working capital borrowings with respect to that period; less
any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
any net decrease in working capital borrowings with respect to that period; plus
any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes the $30 million operating surplus “basket,” net increases in working capital borrowings, net drawdowns of reserves of cash generated in prior periods and amounts held in the distribution reserve or amounts released therefrom to pay distributions.
 
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 after the initial quarterly distribution and the subsequent target distribution levels have been achieved. Our general partner currently holds all of our incentive distribution rights but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

Assuming we do not issue any additional classes of units and our general partner maintains its 2% interest, if we have made distributions to our unitholders from operating surplus in an amount equal to the initial quarterly distribution for any quarter, assuming no arrearages, then we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner as follows:
 
 
Total Quarterly Distribution
Target Amount
 
Marginal Percentage
Interest Distributions
 
 
Common and Subordinated Unitholders
 
General Partner
Initial quarterly distribution
 
$0.425
 
98%
 
2%
First Target Distribution
 
Above $0.425 up to $0.489
 
98%
 
2%
Second Target Distribution
 
Above $0.489 up to $0.531
 
85%
 
15%
Third Target Distribution
 
Above $0.531 up to $0.638
 
75%
 
25%
Thereafter
 
Above $0.638
 
50%
 
50%




34



ITEM 6.        SELECTED FINANCIAL DATA
 
Selected financial data set forth below are derived from our audited consolidated financial statements for the periods indicated. The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and the accompanying notes thereto included elsewhere in this report. 
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
 
2008
 
2007
 
 
(in thousands)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
Revenues (including transactions with affiliates)
 
$
283,790

 
$
399,282

 
$
416,790

 
$
15,000

 
$

Expenses (including transactions with affiliates)
 
139,164

 
118,485

 
88,870

 
32,141

 
12,516

Income (loss) from operations
 
144,626

 
280,797

 
327,920

 
(17,141
)
 
(12,516
)
Other income (expense)
 
(175,645
)
 
(173,229
)
 
(141,008
)
 
(61,203
)
 
(36,436
)
Net income (loss)
 
(31,019
)
 
107,568

 
186,912

 
(78,344
)
 
(48,952
)
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Data:
 
 
 
 
 
 
 
 
 
 
Cash flows provided by (used in) operating activities
 
14,249

 
104,137

 
234,311

 
(1,156
)
 
(640
)
Cash flows provided by (used in) investing activities
 
(8,191
)
 
(5,076
)
 
92,146

 
(560
)
 
(74,776
)
Cash flows provided by (used in) financing activities
 
22,008

 
(163,254
)
 
(208,922
)
 
1,710

 
75,422


 
 
December 31,
 
 
2011
 
2010
 
2009
 
2008
 
2007
 
 
(in thousands)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
81,415

 
$
53,349

 
$
117,542

 
$
7

 
$
13

Restricted cash and cash equivalents (current)
 
13,732

 
13,732

 
13,732

 
235,985

 
191,179

Non-current restricted cash and cash equivalents
 
82,394

 
82,394

 
82,394

 
137,984

 
453,843

Non-current restricted U.S. Treasury securities
 

 

 

 
20,829

 
63,923

Property, plant and equipment, net
 
1,514,416

 
1,550,465

 
1,588,557

 
1,517,507

 
1,127,289

Total assets
 
1,737,300

 
1,743,492

 
1,859,473

 
1,978,835

 
1,904,978

Long-term debt, net of discount
 
2,192,418

 
2,187,724

 
2,110,101

 
2,107,673

 
2,032,000

Long-term debt—related party, net of discount
 

 

 
72,928

 
70,661

 

Long-term debt—affiliate
 

 

 

 
2,372

 
645

Deferred revenue
 
25,500

 
29,500

 
33,500

 
37,500

 
40,000

Deferred revenue—affiliate
 
12,266

 
9,813

 
7,360

 
4,971

 
2,583





35



ITEM 7.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
 
Introduction
 
The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes in "Financial Statements and Supplementary Data." This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis include the following subjects: 
Overview of Business 
Overview of Significant Events 
Liquidity and Capital Resources 
Contractual Obligations 
Results of Operations 
Off-Balance Sheet Arrangements 
Summary of Critical Accounting Policies and Estimates
Recent Accounting Standards
 
Overview of Business
 
We are a Delaware limited partnership formed by Cheniere Energy, Inc. ("Cheniere"). Through our wholly owned subsidiary, Sabine Pass LNG, L.P. ("Sabine Pass LNG"), we own and operate the Sabine Pass LNG terminal located in western Cameron Parish, Louisiana on the Sabine Pass Channel. Through our wholly owned subsidiary, Sabine Pass Liquefaction, LLC ("Sabine Pass Liquefaction"), we are developing a project to add liquefaction capabilities at the Sabine Pass LNG terminal.

Overview of Significant Events
 
In 2011, we maintained commercial operability of the Sabine Pass LNG terminal and continued to execute our strategy to generate steady and reliable revenues under Sabine Pass LNG’s long-term TUAs. Our significant accomplishments since January 1, 2011 include the following:
In January 2011, Sabine Pass Liquefaction and Sabine Pass LNG submitted an application to the FERC requesting authorization to site, construct and operate liquefaction and export facilities at the Sabine Pass LNG terminal.
In January 2011, we initiated an at-the-market program to sell up to 1.0 million common units, the proceeds from which are being used for general business purposes, including to fund development costs associated with our liquefaction project. As of December 31, 2011, we had sold 0.5 million common units with net proceeds of $9.0 million.
In May 2011, Sabine Pass Liquefaction received an order from the U.S. Department of Energy ("DOE") with authorization to export domestically produced natural gas from the Sabine Pass LNG terminal as LNG to any country that has, or in the future develops, the capacity to import LNG and with which trade is permissible.
In September 2011, we sold 3.0 million common units in an underwritten public offering and 1.1 million common units to Cheniere Common Units Holding, LLC ("Cheniere Common Units Holding"), a wholly owned subsidiary of Cheniere, at a price of $15.25 per common unit. We received net proceeds from this offering of approximately $60 million that we are using for general business purposes, including development costs of our project to add liquefaction capacity at the Sabine Pass LNG terminal.
In October 2011, Sabine Pass Liquefaction entered into its first LNG sale and purchase agreement ("SPA") with BG Gulf Coast LNG, LLC ("BG"), an affiliate of BG Energy Holdings Limited, under which BG agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa). This agreement was amended in January 2012 to increase the amount of LNG that BG has agreed to purchase to 286.5 million MMBtu of LNG per year (approximately 5.5 mtpa).



36



In November 2011, Sabine Pass Liquefaction entered into an SPA with Gas Natural Aprovisionamientos SDG S.A. ("Gas Natural Fenosa"), an affiliate of Gas Natural SDG S.A., under which Gas Natural Fenosa has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa).
In November 2011, Sabine Pass Liquefaction entered into a lump sum turnkey engineering, procurement and construction ("EPC") agreement with Bechtel Oil, Gas and Chemicals, Inc. ("Bechtel") for the first two LNG trains and related facilities at the Sabine Pass LNG terminal. The agreement provides that Sabine Pass Liquefaction will pay Bechtel a contract price of $3.9 billion, which is subject to adjustment by change order.
In December 2011, Sabine Pass Liquefaction entered into an SPA with GAIL (India) Limited ("GAIL"), under which GAIL has agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa). Prior to the commencement of LNG train 4 operations, GAIL will purchase bridge volumes of approximately 0.2 mtpa upon the commencement of operations of LNG train 2.
In January 2012, Sabine Pass Liquefaction entered into an SPA with Korea Gas Corporation ("KOGAS"), under which KOGAS agreed to purchase 182.5 million MMBtu of LNG per year (approximately 3.5 mtpa).

Liquidity and Capital Resources
 
Cash and Cash Equivalents
 
As of December 31, 2011, we had $81.4 million of cash and cash equivalents and $96.1 million of restricted cash and cash equivalents, which is restricted to pay interest on the Senior Notes described below.
 
The foregoing funds and cash flows from Sabine Pass LNG are anticipated to be sufficient to fund operating expenditures and interest requirements for at least the next twelve months. Regardless of whether Sabine Pass LNG receives revenues from Cheniere Investments (or us, as guarantor), Sabine Pass LNG expects to have sufficient cash flow from payments made under its Total and Chevron TUAs to allow it to meet its future operating expenditures for at least the next twelve months and interest payment requirements until maturity of the 2013 Notes. In order for us to fund our operations and make distributions to our unitholders, we are dependent on the ability of Sabine Pass LNG to make distributions to us. Sabine Pass LNG must satisfy certain restrictions under the indenture governing the Senior Notes (the "Sabine Pass Indenture") before being able to make distributions to us, which will require that Sabine Pass LNG receive substantial revenues in addition to payments made under its Total Gas and Power North America, Inc. ("Total") and Chevron U.S.A. Inc. ("Chevron") TUAs. If Sabine Pass LNG is unable to make distributions to us, then we will likely be unable to make our anticipated future quarterly cash distributions on our units.

In January 2011, we initiated an at-the-market program to sell up to 1.0 million common units the proceeds from which would be used primarily to fund development costs associated with our proposed liquefaction project at the Sabine Pass LNG terminal. As of December 31, 2011, we had sold 0.5 million common units with net proceeds of $9.0 million. In addition, we received $0.2 million in net proceeds from our general partner in connection with the exercise of its right to maintain its 2% ownership interest in us. During the year ended December 31, 2011, we paid $0.3 million in commissions to Miller Tabak + Co., Inc., as sales agent, in connection with the at-the-market program.

In September 2011, we sold 3.0 million common units in an underwritten public offering and 1.1 million common units to Cheniere Common Units Holding at a price of $15.25 per common unit. We received net proceeds of approximately $60 million from this offering that we are using for general business purposes, including development costs associated with our proposed liquefaction project at the Sabine Pass LNG terminal.

Sabine Pass LNG Terminal
 
Approximately 2.0 Bcf/d of the regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which Sabine Pass LNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Capacity reservation fee TUA payments are made by Sabine Pass LNG's third-party TUA customers as follows: 
Total has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions; and 



37



Chevron has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.
 
Each of Total and Chevron previously paid Sabine Pass LNG $20.0 million in nonrefundable advance capacity reservation fees, which are being amortized over a 10-year period as a reduction of each customer's regasification capacity reservation fees payable under its respective TUA.

In November 2006, Cheniere Marketing reserved approximately 2.0 Bcf/d of regasification capacity under a TUA and was obligated to make capacity payments to Sabine Pass LNG aggregating approximately $250 million per year for the period from January 1, 2009, through at least September 30, 2028. In June 2010, Cheniere Marketing assigned its TUA with Sabine Pass LNG to Cheniere Investments, including all of its rights, titles, interests, obligations and liabilities under the TUA. In connection with the assignment, Cheniere's guarantee of Cheniere Marketing's obligations under the TUA was terminated. Cheniere Investments is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $250 million per year through at least September 30, 2028; however, the revenue earned by Sabine Pass LNG from Cheniere Investments' capacity payments under the TUA is eliminated upon consolidation of our financial statements. We have guaranteed Cheniere Investments' obligations under its TUA.

Concurrently with the TUA assignment, Cheniere Investments entered into a Variable Capacity Rights Agreement ("VCRA") with Cheniere Marketing in order for Cheniere Investments to monetize its capacity at the Sabine Pass LNG terminal. The VCRA will continue until the earliest of (a) the termination of Cheniere Investments' TUA, (b) expiration of the initial term of the TUA, (c) the termination of the VCRA by either party after June 2012, or (d) the termination of the VCRA as a result of default. Prior to 2018, Cheniere Marketing's termination right is subject to our having specified levels of cash reserved for distribution to our common unitholders as of the applicable termination date. Under the terms of the VCRA, Cheniere Marketing is responsible for monetizing the capacity at the Sabine Pass LNG terminal held by Cheniere Investments and has the right to utilize all of the services and other rights at the Sabine Pass LNG terminal available under the TUA assigned to Cheniere Investments. In consideration of these rights, Cheniere Marketing is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG delivered to the Sabine Pass LNG terminal. To the extent payments from Cheniere Marketing to Cheniere Investments under the VCRA increase our available cash in excess of the common unit and general partner distributions and certain reserves, the cash would be distributed to Cheniere in the form of distributions on its subordinated units. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs under the TUA. Cheniere has guaranteed all of Cheniere Marketing's payment obligations under the VCRA. Cheniere Marketing continues to develop its business, lacks a credit rating and may be limited by access to capital. Cheniere, which has guaranteed the obligations of Cheniere Marketing under the VCRA, has a non-investment grade corporate rating.

Under each of the TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered for the customers account.

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

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

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




38



Sources and Uses of Cash
 
The following table summarizes (in thousands) the sources and uses of our cash and cash equivalents for the years ended December 31, 2011, 2010 and 2009. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, that are referred to elsewhere in this report. Additional discussion of these items follows the table.
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
Sources of cash and cash equivalents
 
 
 
 
 
 
Proceeds from sale of partnership units
 
$
70,157

 
$

 
$

Operating cash flow
 
14,249

 
104,137

 
234,311

Use of restricted cash and cash equivalents
 

 

 
298,673

Borrowings under long-term note—affiliate
 

 

 
114

Total sources of cash and cash equivalents
 
84,406

 
104,137

 
533,098

 
 
 
 
 
 
 
Uses of cash and cash equivalents
 
 
 
 
 
 
Distributions to owners
 
(48,149
)
 
(163,249
)
 
(280,675
)
LNG terminal construction-in-process, net
 
(7,137
)
 
(4,955
)
 
(96,918
)
Advances under long-term contracts
 
(1,054
)
 
(121
)
 
(601
)
Special rights adjustment
 

 

 
(34,879
)
Repayment of long-term note—affiliate
 

 

 
(2,467
)
Other
 

 
(5
)
 
(23
)
Total uses of cash and cash equivalents
 
(56,340
)
 
(168,330
)
 
(415,563
)
 
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
 
28,066

 
(64,193
)
 
117,535

Cash and cash equivalents—beginning of year
 
53,349

 
117,542

 
7

Cash and cash equivalents—end of year
 
$
81,415

 
$
53,349

 
$
117,542

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

In September 2011, we sold 3.0 million common units in an underwritten public offering and 1.1 million common units to Cheniere Common Units Holding, LLC at a price of $15.25 per common unit. We received net cash proceeds of $70.2 million from the offering, which are being used for general business purposes, including development costs for the proposed liquefaction facilities at the Sabine Pass LNG terminal.
 
Operating cash flow
 
Operating cash flow decreased $130.2 million from 2009 to 2010. The decrease in operating cash flow primarily resulted from the June 2010 TUA assignment from Cheniere Marketing to Cheniere Investments, effective July 1, 2010, that resulted in the TUA payments being made by Cheniere Investments, our wholly owned subsidiary, instead of being received from Cheniere Marketing. As a result, instead of receiving $250.2 million from Cheniere Marketing TUA payments in 2009, we received only $62.8 million from Cheniere Marketing TUA payments in 2010, resulting in a cash flow decrease of $187.4 million. This operating cash flow decrease was partially offset by obtaining a full year of TUA reservation fee payments from Total and Chevron in 2010, which resulted in $74.7 million of increased operating cash flow. The remaining $17.5 million decrease in operating cash flow resulted primarily from timing in operating and maintenance payments and increased development costs associated with our proposed liquefaction project at the Sabine Pass LNG terminal.

Operating cash flow decreased $89.9 million from 2010 to 2011 primarily as a result of the TUA assignment described above and increased development costs associated with our proposed liquefaction project at the Sabine Pass LNG terminal.



39



 
Use of restricted cash and cash equivalents
 
In 2009, $298.7 million of restricted cash and cash equivalents was primarily used to pay for construction activities at the Sabine Pass LNG terminal.  Under the Sabine Pass Indenture, a portion of the proceeds from the Senior Notes (described below) was initially required to be used for scheduled interest payments through May 2009 and to fund the cost to complete construction of the Sabine Pass LNG terminal. Due to these restrictions imposed by the Sabine Pass Indenture, the proceeds are not presented as cash and cash equivalents, and therefore, when proceeds from the Senior Notes that have been designated as restricted cash and cash equivalents are used, they are presented as a source of cash and cash equivalents. The zero use of restricted cash and cash equivalents in 2010 and 2011 resulted from completing construction of the initial sendout capacity of approximately 2.6 Bcf/d and storage capacity of approximately 10.1 Bcf at the Sabine Pass LNG terminal in September 2008, and the substantial completion of the Sabine Pass LNG terminal’s construction activities during the third quarter of 2009.
 
Distributions to owners
 
We made $48.1 million, $163.2 million and $280.7 million of distributions to our common and subordinated unitholders and to our general partner in 2011, 2010 and 2009, respectively. The progressively decreasing amount of distributions to owners from 2009 to 2011 resulted from the TUA assignment from Cheniere Marketing to Cheniere Investments, effective July 1, 2010, which decreased our available cash in excess of the common unit and general partner distributions. As a result of Cheniere Marketing's assignment of its TUA to Cheniere Investments, we have not paid distributions on our subordinated units since the distribution made with respect to the quarter ended March 31, 2010.

LNG terminal construction-in-process, net
 
Capital expenditures for the Sabine Pass LNG terminal were $7.1 million, $5.0 million and $96.9 million in 2011, 2010 and 2009, respectively. The decreased amounts of capital expenditures in 2011 and 2010 compared to 2009 resulted from substantially completing construction of the Sabine Pass LNG terminal in the third quarter of 2009.  
  
Special rights adjustment
 
In August 2009, we determined that we would not need the remaining balance in the distribution reserve account ("Distribution Reserve Account") to make distributions because we had adequate available cash from Sabine Pass LNG. We, therefore, distributed the remaining balance of $34.9 million in the Distribution Reserve Account to Cheniere pursuant to the terms of our partnership agreement. 

Cash Distributions to Unitholders
 
Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter less the amount of any reserves established by our general partner. All distributions paid to date have been made from operating surplus. The following provides a summary of distributions paid by us during the year ended December 31, 2011:
 
 
 
 
 
 
Total Distribution
 
 
 
 
 
 
(in thousands)
Date Paid
 
Period Covered by Distribution
 
Distribution Per Common Unit
 
Common Units
 
Subordinated Units
 
General Partner Units
February 11, 2011
 
October 1 - December 31, 2010
 
$
0.425

 
$
11,229

 

 
$
229

May 13, 2011
 
January 1, 2011 - March 31, 2011
 
$
0.425

 
$
11,335

 

 
$
231

August 12, 2011
 
April 1, 2011 - June 30, 2011
 
$
0.425

 
$
11,446

 

 
$
234

November 14, 2011
 
July 1, 2011 - September 30, 2011
 
$
0.425

 
$
13,176

 

 
$
269




40



Prior to the TUA assignment from Cheniere Marketing to Cheniere Investments, we had been using cash paid under the Cheniere Marketing TUA to make distributions to Cheniere on our subordinated units held by Cheniere. Subsequent to the assignment of the TUA, the subordinated units will receive distributions only to the extent we have available cash above the minimum quarterly distributions requirement for our common unitholders and general partner along with certain reserves. Such available cash could be generated through new business development or fees received from Cheniere Marketing under the VCRA. As a result of the TUA assignment, the ending of the subordination period and conversion of the subordinated units into common units will depend upon future business development and is no longer expected to occur as early as previously estimated.

On January 20, 2012, we declared a $0.425 distribution per common unit and the related distribution to our general partner to be paid to owners of record on February 1, 2012 for the period from October 1, 2011 to December 31, 2011.
 
Debt Agreements
 
Senior Notes
 
In November 2006, Sabine Pass LNG issued an aggregate principal amount of $2,032.0 million of Senior Notes (the "Senior Notes"), consisting of $550.0 million of 7¼% Senior Secured Notes due 2013 (the "2013 Notes") and $1,482.0 million of 7½% Senior Secured Notes due 2016 (the "2016 Notes"). In September 2008, Sabine Pass LNG issued an additional $183.5 million, before discount, of 2016 Notes whose terms were identical to the previously outstanding 2016 Notes. Interest on the Senior Notes is payable semi-annually in arrears on May 30 and November 30 of each year. The Senior Notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG’s equity interests and substantially all of its operating assets.

Sabine Pass LNG may redeem some or all of the Senior Notes at any time, and from time to time, at a redemption price equal to 100% of the principal plus any accrued and unpaid interest plus the greater of:
1.0% of the principal amount of the Senior Notes; or
the excess of: a) the present value at such redemption date of (i) the redemption price of the Senior Notes plus (ii) all required interest payments due on the Senior Notes (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over b) the principal amount of the Senior Notes, if greater.

Under the Sabine Pass Indenture, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and  there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment of approximately $82.4 million. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass Indenture. During the years ended December 31, 2011, 2010, and 2009, Sabine Pass LNG made distributions to Cheniere Partners of $313.6 million, $374.8 million and $295.7 million, respectively, to us after satisfying all of the applicable conditions in the Sabine Pass Indenture. 
  
Services Agreements
 
During the years ended December 31, 2011, 2010 and 2009, we recorded general and administrative expense—affiliate of $19.0 million, $15.9 million and $18.5 million, respectively, under the following service agreements.

Sabine Pass LNG O&M Agreement

In February 2005, Sabine Pass LNG entered into a 20-year operation and maintenance agreement (the "O&M Agreement") with a wholly owned subsidiary of Cheniere pursuant to which we receive all necessary services required to construct, operate and maintain the Sabine Pass LNG receiving terminal. Sabine Pass LNG is required to pay a fixed monthly fee of $130,000 (indexed for inflation) under the agreement, and the counterparty is entitled to a bonus equal to 50% of the salary component of labor costs in certain circumstances to be agreed upon between Sabine Pass LNG and the counterparty at the beginning of each operating year. In addition, Sabine Pass LNG is required to reimburse the counterparty for its operating expenses, which consist primarily of labor expenses.



41



 Sabine Pass LNG Management Services Agreement

In February 2005, Sabine Pass LNG entered into a 20-year management services agreement ("MSA") with its general partner, which is our wholly owned subsidiary, pursuant to which its general partner was appointed to manage the construction and operation of the Sabine Pass LNG receiving terminal, excluding those matters provided for under the O&M Agreement. In August 2008, the general partner of Sabine Pass LNG assigned all of its rights and obligations under the MSA to Cheniere LNG Terminals, Inc. ("Cheniere Terminals"), a wholly owned subsidiary of Cheniere. Sabine Pass LNG is required to pay Cheniere Terminals a monthly fixed fee of $520,000 (indexed for inflation).

Cheniere Partners Services Agreement

In March 2007, we entered into a services agreement with Cheniere Terminals pursuant to which we would pay Cheniere Terminals an annual administrative fee of $10.0 million (adjusted for inflation) for the provision of various general and administrative services for our benefit following the closing of our initial public offering. Payments under this services agreement commenced January 1, 2009. In addition, we reimburse Cheniere Terminals for its services in an amount equal to the sum of all out-of-pocket costs and expenses incurred by Cheniere Terminals that are directly related to our business or activities.

In June 2010, Cheniere Terminals and we amended, effective as of July 1, 2010, the fee structure for the various general and administrative services provided by Cheniere Terminals for our benefit and changed it from a fixed fee to a variable fee not to exceed $2.5 million per quarter (indexed for inflation). The amended and restated services agreement provides that fees will be paid quarterly from our unrestricted cash and cash equivalents remaining after making distributions to the common unitholders and the general partner in respect of each quarter and retaining certain reserves. Our ability to pay management fees is dependent on Cheniere Terminals' ability to, among other things, manage our and Sabine Pass LNG's operating and administrative expenses, monetize the 2.0 Bcf/d of regasification capacity held by Cheniere Investments and develop new projects through either internal development or acquisition to increase cash flow. 

Contractual Obligations
 
We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2011 (in thousands).
 
 
Payments Due for Years Ended December 31,
 
 
Total
 
2012
 
2013 - 2014
 
2015 - 2016
 
Thereafter
Operating lease obligations (1) (2)
 
$
287,528

 
$
9,647

 
$
19,180

 
$
19,180

 
$
239,521

Long-term debt (excluding interest) (3)
 
2,215,500

 

 
550,000

 
1,665,500

 

Service contracts:
 
 
 
 
 
 
 
 
 
 
Affiliate O&M Agreement (4)
 
21,579

 
1,639

 
3,278

 
3,278

 
13,384

Affiliate Sabine Pass LNG MSA (4)
 
86,315

 
6,556

 
13,111

 
13,111

 
53,537

Affiliate services agreement (4)
 
184,955

 
10,880

 
21,759

 
21,759

 
130,557

Cooperative endeavor agreements (4)
 
12,267

 
2,453

 
4,907

 
4,907

 

Construction and purchase obligations (5)
 
1,363

 
1,363

 

 

 

Other obligation (6)
 
750

 
750

 

 

 

Total
 
$
2,810,257

 
$
33,288

 
$
612,235

 
$
1,727,735

 
$
436,999

 
(1)
A discussion of these obligations can be found in Note 14—"Leases" of our Consolidated Financial Statements.
(2)
Minimum lease payments have not been reduced by a minimum sublease rental of $120.3 million due in the future under non-cancelable tug boat subleases.
(3)
Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2011, our cash payments for interest would be $164.8 million in 2012, $161.5 million in 2013, $124.9 million in 2014, $124.9 million in 2015 and $114.5 million in 2016 for the remaining years for a total of $690.6 million.  See Note 11—"Long-Term Debt" of our Consolidated Financial Statements.
(4)
A discussion of these obligations can be found in Note 13—"Related Party Transactions" of our Consolidated Financial Statements.



42



(5)
A discussion of these obligations can be found at Note 15—"Commitments and Contingencies" of our Notes to Consolidated Financial Statements.
(6)
Other obligation consists of LNG terminal security services.
 
Results of Operations
 
Overall Operations
 
2011 vs. 2010
 
Our consolidated net income decreased $138.6 million, from $107.6 million of net income in 2010 to a $31.0 million net loss in 2011. This decrease in net income primarily resulted from the TUA assignment from Cheniere Marketing to Cheniere Investments, effective July 1, 2010. Beginning July 1, 2010, our affiliate revenues reflect only tug service revenue and the amount of income earned under the VCRA from Cheniere Marketing because the affiliate revenues earned by Sabine Pass LNG from Cheniere Investments' capacity payments under the TUA are eliminated upon consolidation of our financial statements. In addition, the decrease in net income in 2011 was a result of increases in development expenses related to our proposed liquefaction project. These decreases to net income were partially offset by decreased operating and maintenance expenses in 2011 compared to 2010.

2010 vs. 2009
 
Our consolidated net income decreased $79.3 million, from net income of $186.9 million in 2009 to $107.6 million in 2010. This $79.3 million decrease in net income primarily resulted from the TUA assignment from Cheniere Marketing to Cheniere Investments effective July 1, 2010. Beginning July 1, 2010, our affiliate revenues reflect only tug service revenue and the amount of income earned under the VCRA from Cheniere Marketing because the affiliate revenues earned by Sabine Pass LNG from Cheniere Investments' capacity payments under the TUA are eliminated upon consolidation of our financial statements. In addition, the decrease in net income was a result of increases in interest expense, depreciation expense, operating expense and development expense related to our proposed liquefaction project. These decreases to net income were partially offset by decreased operating and maintenance expenses in 2010 compared to 2009.
 
Revenues (including Affiliate Revenues)
 
2011 vs. 2010
 
Total revenues decreased $115.5 million, from $399.3 million in 2010 to $283.8 million in 2011. This decrease primarily resulted from the TUA assignment from Cheniere Marketing to Cheniere Investments, effective July 1, 2010, partially offset by revenues earned under the VCRA. Beginning July 1, 2010, our affiliate revenues primarily reflect the amount of income earned under the VCRA.

2010 vs. 2009
 
Our revenues decreased $17.5 million, from $416.8 million in 2009 to $399.3 million in 2010.  This $17.5 million decrease primarily resulted from a decrease in affiliate revenues resulting from the TUA assignment from Cheniere Marketing to Cheniere Investments, effective July 1, 2010, partially offset by an increase in revenues resulting from the commencement of services under the Total TUA beginning on April 1, 2009 and the Chevron TUA beginning on July 1, 2009.

Development Expense (including Affiliate Expense)
 
2011 vs. 2010

Development expense (including affiliate expense) increased $25.9 million, from $10.6 million in 2010 to $36.5 million in 2011. This increase resulted from costs incurred to develop our proposed liquefaction project at the Sabine Pass LNG terminal.




43



2010 vs. 2009

Development expense (including affiliate expense) increased $10.6 million, from zero in 2009 to $10.6 million in 2010. This increase resulted from costs incurred to develop our proposed liquefaction project at the Sabine Pass LNG terminal.

Operating and Maintenance Expense (including Affiliate Expense)
 
2011 vs. 2010

Operating and maintenance expense (including affiliate expense) decreased $5.5 million, from $39.2 million in 2010 to $33.7 million in 2011. This decrease primarily resulted from decreased fuel costs in 2011 compared to 2010 as a result of efficiencies in our LNG inventory management.

2010 vs. 2009

Operating and maintenance expense (including affiliate expense) increased $6.7 million, from $32.5 million in 2009 to $39.2 million in 2010. This increase primarily resulted from increased tug service costs and increased fuel costs associated with the full operability of the Sabine Pass LNG terminal during all of 2010, as compared to only part of 2009.
 
Interest Expense, net
 
2010 vs. 2009
 
Interest expense, net of amounts capitalized, increased $26.8 million, from $147.2 million in 2009 to $174.0 million in 2010. This increase resulted from the achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009, which reduced the amount of interest expense that was capitalized.

Depreciation Expense
 
2010 vs. 2009

Depreciation expense increased $9.6 million, from $32.7 million in 2009 to $42.3 million in 2010. This increase resulted from our beginning to depreciate the costs associated with the achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009.

Off-Balance Sheet Arrangements
 
As of December 31, 2011, we had no "off-balance sheet arrangements" that may have a current or future material affect on our consolidated financial position or results of operations.
 
Summary of Critical Accounting Policies and Estimates
 
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives but involve an implementation and interpretation of existing rules, and the use of judgment, to apply the accounting rules to the specific set of circumstances existing in our business. In preparing our consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP"), we endeavor to comply with all applicable rules on or before their adoption, and we believe that the proper implementation and consistent application of the accounting rules are critical. However, not all situations are specifically addressed in the accounting literature. In these cases, we must use our best judgment to adopt a policy for accounting for these situations. We accomplish this by analogizing to similar situations and the accounting guidance governing them.
 



44



Cash and Cash Equivalents
 
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
 
Accounting for LNG Activities
 
Generally, we begin capitalizing the costs of LNG terminal projects once the individual project meets the following criteria: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals, and other preliminary investigation and development activities related to our LNG terminals and related pipelines.
 
Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as intangible LNG assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.
 
We capitalize interest and other related debt costs during the construction period of our LNG terminal. Upon commencement of operations, capitalized interest, as a component of the total cost, will be amortized over the estimated useful life of the asset.
 
Revenue Recognition
 
LNG regasification capacity reservation fees are recognized as revenue over the term of the respective TUAs. Advance capacity reservation fees are initially deferred and amortized over a 10-year period as a reduction of a customer's regasification capacity reservation fees payable under its TUA. The retained 2% of LNG delivered for each customer's account at the Sabine Pass LNG terminal is recognized as revenues as Sabine Pass LNG performs the services set forth in each customer's TUA.
 
Debt Issuance Costs 
Debt issuance costs consist primarily of fees incurred that are directly related to the issuance of the Senior Notes. These costs are capitalized and are being amortized to interest expense over the terms of the Senior Notes.
 
Income Taxes 
We are not subject to either federal or state income taxes, as the partners are taxed individually on their proportionate share of our earnings. At December 31, 2011, the tax basis of our assets and liabilities was $315.2 million less than the reported amounts of our assets and liabilities.
 
In November 2006, Sabine Pass LNG and Cheniere entered into a state franchise tax sharing agreement (the “State Tax Sharing Agreement”) pursuant to which Cheniere has agreed to prepare and file all Texas franchise tax returns which Sabine Pass LNG and Cheniere are required to file on a combined basis and to timely pay the combined Texas franchise tax liability. If Cheniere, in its sole discretion, demands payment, then Sabine Pass LNG will pay to Cheniere an amount equal to the Texas franchise tax that Sabine Pass LNG would be required to pay if its Texas franchise tax liability were computed on a separate company basis. The State Tax Sharing Agreement contains similar provisions for other state and local taxes required to be filed by Cheniere and Sabine Pass LNG on a combined, consolidated or unitary basis. The State Tax Sharing Agreement is effective for tax returns first due on or after January 1, 2008.
 
Concentration of Credit Risk 
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash and cash equivalents and restricted cash. We maintain cash balances at financial institutions which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.
 



45



Sabine Pass LNG has entered into certain long-term TUAs with unaffiliated third parties for regasification capacity at our Sabine Pass LNG terminal. We are dependent on the respective counterparties’ creditworthiness and their willingness to perform under their respective TUAs. We have mitigated this credit risk by securing TUAs for a significant portion of our regasification capacity with creditworthy third-party customers with a minimum Standard & Poor’s rating of AA.
 
Property, Plant and Equipment 
Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments are capitalized, while expenditures for maintenance and repairs and general and administrative activities are charged to expense as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-process over the construction period or related debt term, whichever is shorter. We began depreciating equipment and facilities associated with the initial 2.6 billion cubic feet per day ("Bcf/d") of sendout capacity and 10.1 Bcf of storage capacity of the Sabine Pass LNG terminal when they were ready for use in the third quarter of 2008. We began depreciating equipment and facilities associated with the remaining 1.4 Bcf/d of sendout capacity and 6.8 Bcf of storage capacity of the Sabine Pass LNG terminal when they were ready for use in the third quarter of 2009. The Sabine Pass LNG terminal is depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of the Sabine Pass LNG terminal with similar estimated useful lives have a depreciable range between 15 and 50 years. Depreciation of computer and office equipment, computer software, leasehold improvements and vehicles is computed using the straight-line method over the estimated useful lives of the assets, which range from two to ten years. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in operations.
 
Management reviews property, plant and equipment for impairment periodically and whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. No such impairment was recorded for December 31, 2011, 2010 or 2009.
 
Asset Retirement Obligations 
We recognize asset retirement obligations ("AROs") for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.

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

The preparation of consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Actual results could differ from the estimates and assumptions used.
 
Items subject to estimates and assumptions include, but are not limited to, the value of property, plant and equipment. Actual results could differ significantly from our estimates.




46



Recent Accounting Standards 

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

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Cash Investments  

We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation of capital. Such cash investments are stated at historical cost, which approximates fair market value on our Consolidated Balance Sheets.
 
Marketing and Trading Commodity Price Risk  

We have entered into certain derivative instruments to economically hedge the price risk attributable to future purchases of natural gas to be utilized as fuel to operate the Sabine Pass LNG terminal ("Fuel Derivatives") and to hedge the exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory ("LNG Inventory Derivatives"). We use one-day value at risk ("VaR") with a 95% confidence interval and other methodologies for market risk measurement and control purposes. The VaR is calculated using the Monte Carlo simulation method. The table below provides information about our derivative financial instruments that are sensitive to changes in natural gas prices as of December 31, 2011 (in thousands, except for volume and price range data).
Hedge Description
 
Hedge Instrument
 
Contract Volumes (MMBtu)
 
Price Range ($/MMBtu)
 
Final Hedge Maturity Date
 
Fair Value ($)
 
VaR ($)
Fuel Derivatives
 
Fixed price natural gas swaps
 
1,065,000

 
$3.997 - $5.002
 
January 2013
 
$
(1,415
)
 
$
84

LNG Inventory Derivatives
 
Fixed price natural gas swaps
 
1,440,000

 
3.124 - 4.465
 
June 2012
 
1,610

 
6





47



ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
CHENIERE ENERGY PARTNERS, L.P.





48



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

In September of this year, we restated our Annual Report on Form 10-K for the year ended December 31, 2010 and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2011 to present net income (loss) per common unit in our consolidated statements of operations and the related disclosure. Based on our evaluation, we concluded that, due to the existence of a material weakness in internal control over financial reporting in connection with the presentation of earnings per common unit separately from the combined earnings per limited partner, the company’s disclosure controls and procedures were not effective as of the end of the periods covered by the restated reports. For additional information regarding the restatements and the material weakness identified by management, see “Item 9A. Controls and Procedures” in Amendment No. 1 to our Annual Report on Form 10-K/A for the period ended December 31, 2011, and “Item 4. Disclosure Controls and Procedures” in Amendment No. 1 to our Quarterly Report on Form 10-Q/A for the period ended March 31, 2011, both filed with the SEC on September 12, 2011.

The financial statements included in this Form 10-K were prepared with particular attention to the material weakness. Specifically, we enhanced our quarterly process to highlight significant or unusual matters that may require additional accounting research. As part of our fiscal 2011 assessment of internal control over financial reporting, management conducted sufficient testing and evaluation of the implemented controls to ascertain they were designed and operating effectively and concluded that the implemented controls remediated the material weakness in 2011. Based on our assessment, we have concluded that Cheniere Partners' maintained effective internal control over financial reporting as of December 31, 2011, based on criteria in Internal Control—Integrated Framework issued by the COSO.

Cheniere Partners’ independent auditors, Ernst & Young LLP, have issued an audit report on Cheniere Partners’ internal control over financial reporting as of December 31, 2011, which is contained in this Form 10-K.
 
Management’s Certifications
 
The certifications of the Chief Executive Officer and Chief Financial Officer of Cheniere Partners’ general partner required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere Partners’ Form 10-K.
 
                                                                   
Cheniere Energy Partners, L.P.
 
 
By:
Cheniere Energy Partners GP, LLC,
 
Its general partner
 
By:
/s/    CHARIF SOUKI        
 
By:
/s/ MEG A. GENTLE
 
Charif Souki
 
 
Meg A. Gentle
 
Chief Executive Officer
(Principal Executive Officer)
 
 
Chief Financial Officer
(Principal Financial Officer)




49



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Cheniere Energy Partners GP, LLC, and
Unitholders of Cheniere Energy Partners, L.P.

We have audited the accompanying consolidated balance sheets of Cheniere Energy Partners, L.P. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, partners' and owners' capital (deficit), and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cheniere Energy Partners, L.P. and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cheniere Energy Partners, L.P.'s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 24, 2012 expressed an unqualified opinion thereon.


/s/    ERNST & YOUNG LLP
Ernst & Young LLP
Houston, Texas
February 24, 2012





50



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors of Cheniere Energy Partners GP, LLC, and
Unitholders of Cheniere Energy Partners, L.P.
 
We have audited Cheniere Energy Partners, L.P. and subsidiaries' internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Cheniere Energy Partners, L.P. and subsidiaries' management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

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

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

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

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

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




  

/s/    ERNST & YOUNG LLP
Ernst & Young LLP
Houston, Texas
February 24, 2012




51



CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
 
 
December 31,
 
 
2011
 
2010
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
81,415

 
$
53,349

Restricted cash and cash equivalents
 
13,732

 
13,732

Accounts and interest receivable
 
525

 
1,378

Accounts receivable—affiliate
 
328

 
712

Advances to affiliate
 
692

 
3,543

LNG inventory
 
473

 
1,212

LNG inventory - affiliate
 
4,369

 

Prepaid expenses and other
 
7,976

 
4,727

Total current assets
 
109,510

 
78,653

 
 
 
 
 
Non-current restricted cash and cash equivalents
 
82,394

 
82,394

Property, plant and equipment, net
 
1,514,416

 
1,550,465

Debt issuance costs, net
 
17,622

 
22,004

Other
 
13,358

 
9,976

Total assets
 
$
1,737,300

 
$
1,743,492

LIABILITIES AND PARTNERS’ DEFICIT
 
 
 
 
Current liabilities
 
 
 
 
Accounts payable
 
$
704

 
$
1,072

Accounts payable—affiliate
 
530

 

Accrued liabilities
 
16,751

 
17,848

Accrued liabilities—affiliate
 
3,794

 
5,949

Deferred revenue
 
26,629

 
26,592

Deferred revenue—affiliate
 
688

 
673

Other
 
2,722

 

Total current liabilities
 
51,818

 
52,134

 
 
 
 
 
Long-term debt, net of discount
 
2,192,418

 
2,187,724

Deferred revenue
 
25,500

 
29,500

Deferred revenue—affiliate
 
12,266

 
9,813

Other non-current liabilities
 
317

 
329

 
 
 
 
 
Commitments and contingencies
 


 


 
 
 
 
 
Partners' deficit
 
 
 
 
Common unitholders (31,003,154 and 26,416,357 units issued and outstanding at December 31, 2011 and 2010, respectively)
 
(52,774
)
 
(69,191
)
Subordinated unitholders (135,383,831 units issued and outstanding at December 31, 2011 and 2010)
 
(479,197
)
 
(453,896
)
General partner interest (2% interest with 3,395,653 units and 3,302,045 units issued and outstanding at December 31, 2011 and 2010, respectively)
 
(13,048
)
 
(12,921
)
Total partners’ deficit
 
(545,019
)
 
(536,008
)
Total liabilities and partners’ deficit
 
$
1,737,300

 
$
1,743,492






See accompanying notes to consolidated financial statements.



52



CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)

 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
Revenues
 
 
 
 
 
 
Revenues
 
$
269,183

 
$
268,328

 
$
163,862

Revenues—affiliate
 
14,607

 
130,954

 
252,928

Total revenues
 
283,790

 
399,282

 
416,790

 
 
 
 
 
 
 
Expenses
 
 

 
 

 
 

Operating and maintenance expense
 
21,827

 
27,069

 
20,683

Operating and maintenance expense—affiliate
 
11,918

 
12,090

 
11,833

Depreciation expense
 
42,943

 
42,299

 
32,742

Development expense
 
32,448

 
8,738

 

Development expense—affiliate
 
4,025

 
1,824

 

General and administrative expense
 
5,534

 
6,190

 
3,722

General and administrative expense—affiliate
 
20,469

 
20,275

 
19,890

Total expenses
 
139,164

 
118,485

 
88,870

 
 
 
 
 
 
 
Income from operations
 
144,626

 
280,797

 
327,920

 
 
 
 
 
 
 
Other income (expense)
 
 

 
 

 
 

Interest expense, net
 
(173,590
)
 
(174,016
)
 
(147,201
)
Interest expense—affiliate
 

 

 
(13
)
Derivative gain (loss), net
 
(2,251
)
 
461

 
5,277

Other
 
196

 
326

 
929

Total other expense
 
(175,645
)
 
(173,229
)
 
(141,008
)
 
 
 
 
 
 
 
Net income (loss)
 
$
(31,019
)
 
$
107,568

 
$
186,912

 
 
 
 
 
 
 
Basic and diluted net income per common unit
 
$
1.23

 
$
1.70

 
$
1.13

 
 
 
 
 
 
 
Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation
 
27,910

 
26,416

 
26,416



















See accompanying notes to consolidated financial statements.



53



CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ AND
OWNERS’ CAPITAL (DEFICIT)
(in thousands)
 
 
 
Common
Units
 
Subordinated Units
 
General
Partner
Units
 
Total
Balance, December 31, 2008
 
$
(23,520
)
 
$
(318,994
)
 
$
(9,171
)
 
$
(351,685
)
Net income
 
29,907

 
153,268

 
3,737

 
186,912

Distributions
 
(44,909
)
 
(230,153
)
 
(5,613
)
 
(280,675
)
Special rights adjustment
 
(2,972
)
 
(31,147
)
 
(760
)
 
(34,879
)
Balance, December 31, 2009
 
(41,494
)
 
(427,026
)
 
(11,807
)
 
(480,327
)
 
 
 
 
 
 
 
 
 
Net income
 
17,211

 
88,206

 
2,151

 
107,568

Distributions
 
(44,908
)
 
(115,076
)
 
(3,265
)
 
(163,249
)
Balance, December 31, 2010
 
(69,191
)
 
(453,896
)
 
(12,921
)
 
(536,008
)
 
 
 
 
 
 
 
 
 
Net loss
 
(5,098
)
 
(25,301
)
 
(620
)
 
(31,019
)
Common units sold
 
68,701

 

 
1,456

 
70,157

Distributions
 
(47,186
)
 

 
(963
)
 
(48,149
)
Balance, December 31, 2011
 
$
(52,774
)
 
$
(479,197
)
 
$
(13,048
)
 
$
(545,019
)
 
































See accompanying notes to consolidated financial statements.



54



CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
 
Year Ended December 31,
 
 
2011
 
2010
 
2009
Cash flows from operating activities
 
 
 
 
 
 
Net income (loss)
 
$
(31,019
)
 
$
107,568

 
$
186,912

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 


 
 
 
 
Depreciation
 
42,943

 
42,299

 
32,742

Non-cash LNG inventory—-affiliate write-downs
 
10,600

 

 

Amortization of debt discount
 
4,695

 
4,695

 
4,695

Amortization of debt issuance costs
 
4,382

 
4,863

 
3,818

Non-cash derivative (gain) loss
 
(195
)
 
124

 
1,106

Changes in operating assets and liabilities:
 
 
 
 
 
 

Accounts and interest receivable
 
853

 
(626
)
 
1,526

Accounts receivable—affiliate
 
384

 
2,874

 
(3,167
)
Accounts payable and accrued liabilities
 
(1,173
)
 
3,035

 
(11,517
)
Accounts payable and accrued liabilities—affiliate
 
(1,640
)
 
2,566

 
2,685

Deferred revenue—affiliate
 
15

 
(62,833
)
 
765

Deferred revenue
 
(3,964
)
 
(3,864
)
 
19,955

Advances to affiliate
 
2,851

 
1,815

 
(3,160
)
LNG inventory—affiliate
 
(14,969