Edgar Filing: Cheniere Energy Partners, L.P.

CQP 2010 Form 10KA

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

Amendment No. 1



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

For the fiscal year ended December 31, 2010



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 o No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer 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 $264,856,500 as of June 30, 2010.

The issuer had 26,421,023 common units and 135,383,831 subordinated units outstanding as of February 21, 2011.

Documents incorporated by reference: None

EXPLANATORY NOTE

We are filing this Amendment No. 1 on Form 10-K/A (the “Amended Filing”) to our Annual Report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission (“SEC”) on March 3, 2011 (the “Original Filing”) to present net income (loss) per common unit on our consolidated statements of operations and in the related disclosure found in Part II - Item 8. Financial Statements and Supplementary Data.

In accordance with applicable SEC rules, this Amended Filing includes certifications from our Chief Executive Officer and Chief Financial Officer dated as of the date of this filing.

Except for the items noted above, no other information included in the Original Filing is being amended by this Amended Filing. The Amended Filing continues to speak as of the date of the Original Filing and we have not updated the Original Filing to reflect events occurring subsequent to the date of the Original Filing other than those associated with the presentation of net income (loss) per common unit on our consolidated statements of operations and in the related disclosure. Accordingly, this Amended Filing should be read in conjunction with our filings made with the SEC subsequent to the date of the Original Filing.

Background of the Restatement

In response to correspondence with the SEC, we are filing this amendment to present the earnings per common unit instead of the combined earnings per limited partner unit. For the year ended December 31, 2010, the earnings per common unit of $1.70 on our consolidated statements of operations are greater than our historical presentation of combined earnings per limited partner unit of $0.65 even though our total earnings have not changed. For the years ended December 31, 2009 and 2008, the amounts disclosed were unchanged. For more information regarding the calculation of net income (loss) per common unit, please refer to Note 16—Cash Distributions and Net Income (Loss) per Common Unit.

Internal Control Considerations

We are responsible for establishing and maintaining adequate internal control over financial reporting 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. In the Original Filing, we reported in Part II—Item 9A, that our disclosure controls and procedures and our internal control over financial reporting were effective. In connection with the restatement described in Note 16 to our Consolidated Financial Statements, management identified a material weakness in our internal control over financial reporting as of the date of the Original Filing. As a result of the material weakness, management has concluded that our disclosure controls and procedures were not effective in providing reasonable assurance that the net income (loss) per common unit in our Consolidated Financial Statements was presented in accordance with specific generally accepted accounting principles literature. Our disclosure controls and procedures were not designed to timely identify the effect of changes in distributions to the subordinated units on the presentation of net income (loss) per common unit. Management's revised assessment is included under Part II—Item 9A of this Amended Filing and Management's Report on Internal Control Over Financial Reporting in our Consolidated Financial Statements on page 47 of this Amended Filing.

Restatement of Other Financial Statements

In addition to this Amended Filing, we are filing an amendment to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2011. The amendment to our Quarterly Report on Form 10-Q will be filed to present our net income (loss) per common unit on our consolidated statements of operations and in the related disclosure.

CHENIERE ENERGY PARTNERS, L.P

Index to Form 10-K



PART I	1
Items 1. and 2. Business and Properties	1
General	1
Overview of the LNG Industry	1
Our Business Strategy	1
Market Factors	2
Our Business	2
Employees and Labor Relations	6
Available Information	7
Item 1A. Risk Factors	8
Risks Relating to Our Financial Matters	8
Risks Relating to Our Business	10
Risks Relating to Our Cash Distributions	19
Risks Relating to an Investment in Us and Our Common Units	23
Risks Relating to Tax Matters	27
Item 1B. Unresolved Staff Comments	31
Item 3. Legal Proceedings	31
Item 4. (Removed and Reserved)	31
PART II	31
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	31
Item 6. Selected Financial Data	34
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation	35
Introduction	35
Overview of Business	35
Overview of Significant 2010 Events	35
Liquidity and Capital Resources	36
Contractual Obligations	42
Results of Operations	42
Off-Balance Sheet Arrangements	44
Summary of Critical Accounting Policies	44
Recent Accounting Standards	45
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	45
Item 8. Financial Statements and Supplementary Data	46
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	71
Item 9A. Controls and Procedures	71
Item 9B. Other Information	71
PART III	72
Item 10. Directors, Executive Officers of Our General Partner and Corporate Governance	72
Item 11. Executive Compensation	75
Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Unitholder Matters	78
Item 13. Certain Relationships and Related Transactions, and Director Independence	79
Item 14. Principal Accountant Fees and Services	81
PART IV	82
Item 15. Exhibits and Financial Statement Schedules	82

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;


•	our expected receipt of cash distributions from Sabine Pass LNG, L.P.;


•	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; export 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, memoranda of understanding ("MOUs"), construction contracts and other contracts;


•	statements relating to the construction and operations of our proposed liquefaction project, 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 that we expect to receive an order from the U.S. Department of Energy ("DOE") authorizing us to export domestically produced natural gas as LNG to certain countries, 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.

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;


•	EPCM means engineering, procurement, construction and management;


•	LNG means liquefied natural gas;


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


•	MMBtu means million British thermal units;


•	MMcf/d means million cubic feet per day;


•	MOU means memorandum of understanding;


•	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”) in 2007. 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. We are developing a liquefaction project to provide bi-directional LNG import and export service at the Sabine Pass LNG terminal. 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.

Overview of the LNG Industry

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

Our Business Strategy

Our primary business objectives are to operate the Sabine Pass LNG terminal, develop our liquefaction project and generate stable cash flows sufficient to pay the initial quarterly distribution to our unitholders and, over time and upon satisfaction of these objectives, to increase our quarterly cash distribution. We intend to achieve these objectives by executing the following strategies:


•	successfully managing the operation of the Sabine Pass LNG terminal;


•	monetizing the 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal held by one of our subsidiaries, Cheniere Energy Investments, LLC ("Cheniere Investments") by:


◦	entering into long-term commercial agreements for regasification or bi-directional service;


◦	expanding operations to include bi-directional service capabilities;


◦	developing a portfolio of long-term, short-term and spot LNG purchase and sale agreements; and


◦	entering into business relationships for the marketing of natural gas that is processed at the Sabine Pass LNG terminal; 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 pipelines.

Market Factors

Our ability to successfully execute our business strategies will be impacted by many factors, including: changes in worldwide supply and demand for natural gas and LNG; the relative prices for natural gas in North America and international markets; the willingness of LNG producers and international LNG buyers to invest new capital and secure access to North American natural gas markets on a long-term basis; and access to capital to market natural gas and LNG and to develop and construct liquefaction or future infrastructure projects.

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. In addition, global buyers of natural gas will need to source additional energy supplies to meet future economic growth and balance their energy portfolios. Most of the rapidly growing natural gas markets are in developing countries in Asia, particularly India and China, the Middle East and South America.

In recent years, North American domestic natural gas production has been on an upward trend, due in part to rapid growth in unconventional natural gas basins coupled with technological advances in horizontal drilling. As a result, natural gas reserves and production in North America have increased significantly, while demand for natural gas in North America has been decreasing as a result of a variety of factors, including improved energy efficiency and shifting economic activities to less energy-dependent activities. In response to the shifting global and domestic natural gas market fundamentals, which have reduced demand for LNG regasification services in North America, we are developing our liquefaction project to expand our operations at the Sabine Pass LNG terminal to provide bi-directional import and export service to new customers. We believe that the bi-directional service would offer customers an attractively priced option to access the North American market for natural gas supply or natural gas demand, as global fundamentals dictate. The new service would utilize the LNG storage capacity, ship berthing rights, and regasification capacity that we hold at the Sabine Pass LNG terminal through our subsidiary.

Our Business

Sabine Pass LNG operates the Sabine Pass LNG terminal in western Cameron Parish, Louisiana, on the Sabine Pass Channel. In 2003, Cheniere formed Sabine Pass LNG to own, develop and operate the Sabine Pass LNG terminal. Sabine Pass LNG has long-term leases for three tracts of land consisting of 853 acres in Cameron Parish, Louisiana. The Sabine Pass LNG terminal has a 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 June 2010, Cheniere Marketing, LLC (“Cheniere Marketing”), a wholly owned subsidiary of Cheniere, assigned its TUA with Sabine Pass LNG to Cheniere Investments, our wholly owned subsidiary, effective July 1, 2010. Concurrently, Cheniere Investments entered into a Variable Capacity Rights Agreement (“VCRA”), described below, with Cheniere Marketing in order for Cheniere Investments to monetize its TUA capacity at the Sabine Pass LNG terminal in exchange for compensation based upon the profitability of each transaction undertaken by Cheniere Marketing.

In June 2010, we initiated a project to add liquefaction facilities at the Sabine Pass LNG terminal that would transform the Sabine Pass LNG terminal into a bi-directional LNG terminal capable of liquefying natural gas and exporting LNG in addition to importing and regasifying foreign-sourced LNG.

Customers

The entire approximately 4.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal has been contracted under two 20-year, firm commitment TUAs with unaffiliated third parties, and a third TUA with Cheniere Investments. Each of the three customers at the Sabine Pass LNG terminal must make the full contracted amount of capacity reservation fee payments under its TUA whether or not it uses any of its reserved capacity. Capacity reservation fee TUA payments will be made by the Sabine Pass LNG third-party customers as follows:


•	Total Gas and Power North America, Inc. (“Total”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions; and


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

In November 2006, Cheniere Marketing reserved approximately 2.0 Bcf/d of regasification capacity under a TUA and was required to make capacity payments 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 required to make approximately $250 million per year of capacity payments to Sabine Pass LNG through at least September 30, 2028. 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.

Concurrent with the TUA assignment, Cheniere Investments entered into a 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 two years, or (d) the termination of the VCRA as a result of default. Prior to 2018, Cheniere Marketing's termination right is subject to Cheniere Partners' having specified levels of cash reserved for distribution to its common unitholders as of the applicable termination date. Under the terms of the VCRA, Cheniere Marketing will be responsible for monetizing the capacity at the Sabine Pass LNG terminal held by Cheniere Investments and will have 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 the Cheniere Partners subordinated units held by Cheniere. 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 also 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 Project

In June 2010, we initiated a project to add liquefaction services at the Sabine Pass LNG terminal that would transform the terminal into a bi-directional facility capable of liquefying natural gas and exporting LNG in addition to importing and regasifying foreign-sourced LNG. As currently contemplated, the liquefaction project would be designed and permitted for up to four LNG Trains, each with a nominal production capacity of approximately 4.0 mtpa. We anticipate LNG export from the Sabine Pass LNG terminal could commence as early as 2015, and may be constructed in phases, with each LNG Train commencing operations approximately six to nine months after the previous LNG Train.

We intend for Sabine Pass Liquefaction, LLC ("Sabine Liquefaction"), our wholly owned subsidiary, to enter into long-term, fixed-fee contracts for at least 3.5 mtpa (approximately 0.5 Bcf/d) of bi-directional LNG processing capacity per LNG Train, for a fee between $1.40 and $1.75 per MMBtu, before reaching a final investment decision regarding the development of the LNG Trains. As of February 25, 2011, Sabine Liquefaction had entered into eight non-binding memoranda of understanding (“MOU”) with potential customers for the proposed bi-directional facility representing a total of up to 9.8 mtpa of capacity. Each MOU is subject to negotiation and execution of definitive agreements and certain other customary conditions and does not represent a final and binding agreement with respect to its subject matter. We are negotiating definitive agreements with these and other potential customers.

In August 2010, Sabine Liquefaction received approval from the FERC to begin the pre-filing process required to seek authorization to commence construction of the liquefaction project. In January 2011, the pre-filing period was completed and therefore Sabine Liquefaction submitted an application to the FERC requesting authorization to site, construct and operate liquefaction and export facilities at the Sabine Pass LNG terminal. In September 2010, the DOE granted Sabine Liquefaction an order authorizing Sabine Liquefaction to export up to 16 mtpa (approximately 800 Bcf per year) of domestically produced LNG 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. In September 2010, Sabine Liquefaction filed a second application requesting expansion of the order to include countries with which the U.S. does not have an FTA.

Sabine 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 cost estimate. We currently estimate that total construction costs will be consistent with other recent liquefaction expansion projects constructed by Bechtel, or approximately $400 per metric ton, before financing costs. We have additional work to complete with Bechtel to be able to make an estimate specific to our site and project. Our cost estimates are subject to change due to factors such as changes in design, increased component and material costs, escalation of labor costs, cost overruns and increased spending to maintain a construction schedule.

In December 2010, Sabine Liquefaction engaged SG Americas Securities, LLC, the U.S. broker-dealer subsidiary of Societe Generale Corporate & Investment Banking (SG CIB) for general financial strategy and planning in connection with the development and financing of liquefaction facilities at the Sabine Pass LNG terminal.

We will contemplate making a final investment decision to commence construction of the liquefaction project upon, among other things, entering into acceptable commercial arrangements, receiving regulatory authorization to construct and operate the liquefaction assets and obtaining adequate financing.

LNG Terminal Competition

Our LNG terminal business competes with other companies that are constructing and operating LNG terminals in the U.S. and in other places around the world. According to the FERC, as of December 31, 2010, there were nine existing LNG receiving terminals in North America, two of which are offshore facilities for receiving natural gas regasified from LNG onboard specialized LNG vessels, as well as other new LNG receiving terminals or expansions approved or proposed to be constructed. To the extent that we may desire to sell regasification capacity in our LNG terminal, we will compete with other third-party LNG receiving terminals or existing terminals having uncommitted capacity. In connection with our efforts to obtain LNG to exploit Cheniere Investments' retained regasification capacity at the Sabine Pass LNG terminal, we must compete in the world LNG market to purchase and transport cargoes of LNG.

With the development of liquefaction facilities at the Sabine Pass LNG terminal, we will compete with existing and proposed liquefaction facilities worldwide in our attempt to enter into commercial arrangements for providing bi-directional services at the Sabine Pass LNG terminal. At least three other companies have announced plans to develop liquefaction facilities in North America.

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 the liquefaction project, and failure to comply with such laws could result in substantial penalties. 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 (“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. 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 and the Natural Gas Policy Act of 1978 (“NGPA”), and any rules, regulations or orders of the FERC issued under these acts, 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 the liquefaction project 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 and the liquefaction project are subject to various federal, state and local laws and regulations relating to the protection of the environment. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial liabilities for non-compliance or releases. Failure to comply with these laws and regulations may also result in substantial civil and criminal fines and penalties.

Clean Air Act (CAA)

The Sabine Pass LNG terminal operations and the liquefaction project 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 operations of the Sabine Pass LNG terminal, or the construction and operation of our liquefaction project, will be materially 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 on October 30, 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 November 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 and the liquefaction project 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 and the liquefaction project 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.

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 21, 2010, Cheniere had 196 full-time employees. See Note 12—“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 stockholder, without charge, copies of our Annual Report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Cheniere Energy 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.

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

We have substantial indebtedness, which we will need to refinance, extend or otherwise satisfy, in whole or in part at or prior to maturity.

We will need to refinance, extend or otherwise satisfy $2.2 billion of indebtedness, consisting primarily of $550.0 million of 7¼% Senior Secured Notes due 2013 and $1,665.5 million of 7½% Senior Secured Notes due 2016. We may not be able to refinance, extend or otherwise satisfy our indebtedness as needed, on commercially reasonable terms or at all.

The terms of additional debt, or debt incurred to repay, refinance or extend the Sabine Pass debt, may adversely affect us.

In order to obtain many types of financing, we may have to accept terms that are disadvantageous to us or that may have an adverse impact on our current or future business, operations or financial condition. For example:


•	borrowings, debt issuances, or extensions of debt maturities may subject us to certain restrictive covenants, including covenants restricting our ability to raise additional capital or cross-defaults to other indebtedness;


•	borrowings or debt issuances at the project level may subject the project entity to restrictive covenants, including covenants restricting its ability to make distributions to us or limiting our ability to sell our interests in such entity;


•	offerings of our equity securities could cause substantial dilution for holders of our common units;


•	additional sales of interests in our projects would reduce our interest in future revenues; and


•	the prepayment of fees by, or a business development loan from; prospective customers would reduce future revenues after a facility commences operations.

Our substantial indebtedness and restrictions contained in existing or future debt agreements could adversely affect our ability to operate our business and pursue our liquefaction project, and could prevent us from satisfying or refinancing our debt obligations.

Our substantial indebtedness and restrictions contained in existing or future debt agreements could have important adverse consequences, including:


•	limiting our ability to attract customers;


•	limiting our ability to compete with other companies that are not as highly leveraged;


•	limiting our flexibility in and ability to plan for or react to changing market conditions in our industry and to economic downturns, and making us more vulnerable than our less leveraged competitors to an industry or economic downturn;


•	limiting our ability to use operating cash flow in other areas of our business or for distributions to our unitholders because we must dedicate a substantial portion of these funds to service debt, including indebtedness that we may incur in the future;


•	limiting our ability to obtain additional financing to fund the expansion of the Sabine Pass LNG terminal to provide bi-direction service, our capital expenditures, working capital, acquisitions, debt service requirements or liquidity needs for general business or other purposes; and


•	resulting in a material adverse effect on our business, results of operations and financial condition if we are unable to service or refinance our indebtedness or obtain additional financing, as needed.

Our substantial indebtedness and the restrictive covenants contained in our existing or future debt agreements may not allow us the flexibility that we need to operate our business in an effective and efficient manner and may prevent us from taking advantage of strategic and financial opportunities that would benefit our business, such as our liquefaction project.

If we are unsuccessful in operating our business or taking advantage of such opportunities, due to our substantial indebtedness or other factors, we may be unable to repay, refinance, or extend our indebtedness on commercially reasonable terms or at all.

To service our indebtedness, we require significant amounts of cash flow from operations.

We require significant amounts of cash flow from operations in order to make annual interest payments of approximately $164.8 million on the Senior Notes. Our ability to make payments on and to refinance our indebtedness, including the Senior Notes, and to fund our capital expenditures will depend on our ability to generate cash in the future. Our business may not generate sufficient cash flow from operations, currently anticipated costs may increase, or future borrowings may not be available to us, which could cause us to be unable to pay or refinance our indebtedness, including the Senior Notes, or to fund our other liquidity needs.

The indenture governing the Senior Notes contains restrictions that limit our flexibility in operating our business.

The indenture, dated as of November 9, 2006, governing the Senior Notes contains several significant covenants that, among other things, restrict our ability to:


•	incur additional indebtedness;


•	create liens on our assets; and


•	engage in sale and leaseback transactions and mergers or acquisitions and to make equity investments.

Under some circumstances, these restrictive covenants may not allow us the flexibility that we need to operate our business in an effective and efficient manner and may prevent us from taking advantage of strategic and financial opportunities that would benefit our business. See also “-Risks Relating to Our Cash Distributions-Sabine Pass LNG may be restricted under the terms of the Sabine Pass Indenture from making distributions to us and from incurring additional indebtedness under certain circumstances, which may limit our ability to pay or increase distributions to our unitholders.”

If we fail to comply with the restrictions in the indenture governing the Senior Notes or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies.

We could incur more indebtedness in the future, which could exacerbate the risks associated with our substantial leverage.

The indenture governing the Senior Notes does not prohibit us from incurring additional indebtedness, including additional senior or secured indebtedness, and other liabilities, or from pledging assets to secure such indebtedness and liabilities. The incurrence of additional indebtedness and, in particular, the granting of a security interest to secure additional indebtedness, could adversely affect our business, results of operations and financial condition if we are unable to service our indebtedness.

Our ability to generate needed amounts of cash is substantially dependent upon our TUAs with two third-party Sabine Pass LNG customers, and we will be materially and adversely affected if either customer fails to perform its TUA obligations for any reason.

Our future results and liquidity are 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. We are dependent on each customer's continued willingness and ability to perform its obligations under its TUA. We are also exposed to the credit risk of the guarantors of these customers' obligations under their respective TUAs in the event that we must seek recourse under a guaranty. If either customer fails to perform its obligations under its TUA, 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 TUA.

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

Each of our long-term TUAs contains various termination rights. For example, each customer may terminate its TUA if

the Sabine Pass LNG terminal experiences a force majeure delay for longer than 18 months, fails to redeliver a specified amount of natural gas in accordance with the customer's redelivery nominations or fails to accept and unload a specified number of the customer's proposed LNG cargoes. We may not be able to replace these TUAs on desirable terms, or at all, if they are terminated.

Our ability to satisfy our payment obligations is further dependent upon Cheniere Marketing satisfying its obligations to us under the VCRA.

Under the VCRA, Cheniere Marketing is required to pay us 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' capacity at the Sabine Pass LNG terminal to the extent that neither Cheniere Marketing nor Cheniere Investments is obligated to the contrary under any other agreements. Cheniere Marketing is further obligated to make payments to us up to a maximum of $1.6 million per year to the extent that we have a shortfall between our available cash and initial quarterly distributions to our common unitholders.

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.

In pursuing each aspect of its planned business, Cheniere Marketing will encounter intense competition, including competition from major energy companies and other competitors with significantly greater resources. Cheniere Marketing will also compete with Sabine Pass LNG's other customers and may compete with Cheniere and its other subsidiaries that are developing or operating other LNG terminals and related infrastructure, which may include vessels, pipelines and LNG storage. As discussed below under “—Risks Relating to Our Business—We may be unable to commercially exploit the capacity at the Sabine Pass LNG terminal that we have reserved for our own account”, there are significant risks attendant to Cheniere Marketing's future ability to generate operating cash flow.

In order to generate needed amounts of cash, we may sell 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 may pursue issuances and sales of additional common units. 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.

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 third-party 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. The two third-party customers of Sabine Pass LNG have the obligation to procure LNG to maintain the cryogenic readiness of the terminal. If a third-party customer procures the LNG, the other third-party customer and Sabine Pass LNG will reimburse the procuring customer for each of their allocable share of the LNG acquired to maintain the cryogenic readiness of the Sabine Pass LNG terminal. Should such third-party customers fail to procure the necessary LNG, Sabine Pass LNG has the right to procure the LNG. If Sabine Pass LNG is not able to obtain financing on acceptable terms, then 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 third-party customers and sells the regasified LNG. Sabine Pass LNG may bear the commodity price and other risks of purchasing LNG, holding it in its inventory for a period of time and selling the regasified LNG.

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

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

Hurricanes or other disasters could adversely affect us.

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

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 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, such authorizations are subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed.

We will require governmental approvals and authorizations to implement our proposed business strategy to construct and operate a liquefaction and LNG export facility at the Sabine Pass LNG terminal site. In particular, we will need authorization from the FERC to construct and operate our proposed liquefaction facilities. In addition, although we have received an order from the DOE permitting us to export natural gas to the FTA countries, we are seeking to expand the permit to allow export to non-FTA countries.

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 and prospects.

We may not be able to enter into satisfactory commercial arrangements with third-party customers for bi-directional service at the Sabine Pass LNG terminal.

Our ability to obtain financing for our proposed liquefaction facilities is expected to be contingent upon, among other things, our ability to enter into sufficient long-term commercial agreements in advance of the commencement of construction. To date, we have not entered into any definitive third-party agreements for our proposed liquefaction facilities, and we may not be successful in negotiating such agreements.

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

Key factors that may affect the timing of, and our ability to complete the expansion project at the Sabine Pass LNG terminal to add bi-directional service include, but are not limited to:


•	the issuance and/or continued availability of necessary permits, licenses and approvals from the FERC and the DOE, other governmental agencies and third parties as are required to construct and operate the expansion project;


•	the availability of sufficient financing on reasonable terms;


•	our ability to obtain satisfactory long-term agreements with customers for bi-directional service and for these customers to perform under those agreements during the terms thereof and to maintain their creditworthiness;


•	our ability to enter into a satisfactory agreement with an engineering, procurement, construction and other contractors and to maintain good relationships with these contractors in order to construct the liquefaction facilities, and the ability of those contractors to perform their obligations under the contracts and to maintain their creditworthiness;


•	our customers' ability to enter into satisfactory arrangements to provide or secure pipeline access required for bi-directional service;


•	unanticipated changes in domestic and international market demand for and supply of natural gas and LNG, which will depend, in part, on supplies of, and prices for, alternative energy sources and the discovery of new sources of natural resources;


•	competition with other domestic and international LNG terminals;


•	local and general economic conditions;


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


•	resistance in the local community to the expansion of the Sabine Pass LNG terminal;


•	labor disputes; and


•	weather conditions, such as hurricanes.

Delays in the construction of the Sabine Pass LNG expansion project beyond the estimated development periods, as well as cost overruns, 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 expansion project is constructed (which could cause further delays). Any delay in completion of the expansion project may also cause a delay in the receipt of revenues projected from the expansion project 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 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 17, 2011, Cheniere and its subsidiaries had 196 full-time employees. 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 would likely result in a significant interference with operations and increased costs.

We may not be successful in implementing our proposed business strategy to provide liquefaction services at the Sabine Pass LNG terminal.

Our proposed addition of liquefaction facilities and services at the Sabine Pass LNG terminal will require very significant financial resources, which may not be available on terms reasonably acceptable to us or at all. Cost overruns or delays could adversely affect permitting or construction of the liquefaction facilities. We also may not be able to obtain customer commitments to use the liquefaction services, without which we would not be able to finance the construction of liquefaction facilities. 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 we may not be successful implementing our business strategy, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

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

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

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

Existing and future environmental and similar laws and regulations could result in increased compliance costs or additional operating 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 and 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 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 or 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 costs and restrictions could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

We may be unable to commercially exploit the capacity at the Sabine Pass LNG terminal that we have reserved for our own account.

Our ability to utilize all of our 2.0 Bcf/d of LNG regasification capacity reserved at the Sabine Pass LNG terminal will depend upon whether we can successfully enter into TUAs for some or all of the reserved capacity, enter into term LNG purchase agreements for the reserved capacity, or purchase spot cargoes. We will encounter significant competition and may encounter many expenses, delays, problems and difficulties that we have not anticipated and for which we have not planned in our efforts to commercially exploit Cheniere Investments' reserved TUA regasification capacity. Our success will be significantly dependent upon the ability of us and Cheniere Marketing, on our behalf, to commercially exploit the TUA capacity that Cheniere Investments has reserved at the Sabine Pass LNG terminal, which is subject to substantial risks, including the following:


•	neither Cheniere Investments nor Cheniere Marketing has unconditional agreements or arrangements for any supplies of LNG or for the utilization of Cheniere Investments, reserved regasification capacity, and neither may be able to obtain such agreements or arrangements on economical terms, or at all;


•	neither Cheniere Investments nor Cheniere Marketing has unconditional commitments from customers for the purchase of the natural gas that they propose to sell from the Sabine Pass LNG terminal, and neither may be able to obtain commitments or other arrangements on economical terms, or at all;


•	in order to arrange for supplies of LNG, and for transportation, storage and sales of natural gas, Cheniere Investments will require significant credit support and funding, which we may not be able to obtain on terms that are acceptable to us, or at all; and

•

even if Cheniere Investments or Cheniere Marketing is able to arrange for and finance supplies and transportation of LNG to the Sabine Pass LNG terminal, and for transportation, storage and sales of natural gas to customers, it may experience negative cash flows and adverse liquidity effects due to fluctuations in supply, demand and price for LNG, for transportation of LNG, for natural gas and for storage and transportation of natural gas.

The business plans of both Cheniere Investments and Cheniere Marketing may also be limited by access to capital and Cheniere Marketing's and Cheniere Investments' lack of credit ratings. These factors create financial obstacles and exacerbate the risk that neither Cheniere Investments nor Cheniere Marketing will be able to enter into commercial arrangements with third parties to commercially exploit all of the reserved regasification capacity at the Sabine Pass LNG terminal on commercially advantageous terms, or at all.

Any or all of these factors, as well as risk factors described elsewhere herein and other risk factors that we may not be able to anticipate, control or mitigate, could have a material adverse effect on our ability to commercially exploit Cheniere Investments' reserved regasification capacity at the Sabine Pass LNG terminal, which in turn could materially and adversely affect our business, results of operations, financial condition, prospects and liquidity.

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) or 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.

Failure of imported LNG to be a competitive source of energy for North American markets could adversely affect TUA customers and could materially and adversely affect our business, results of operations, financial condition and prospects.

The success of the regasification component of our business is primarily dependent upon LNG being a competitive source of energy in North America. In North America, due mainly to a historically abundant supply of natural gas and recent discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. The success of the regasification services component of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to North America at a lower cost than the cost to produce some domestic supplies of natural gas, or other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas have recently been and may continue to be discovered in North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than imported LNG. In addition to natural gas, LNG also competes in North America with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy.

Other continents have a longer history of importing LNG and, due to their geographic proximity to LNG producers and limited pipeline access to natural gas supplies, may be willing and able to pay more for LNG, thereby reducing or eliminating the supply of LNG available in North American markets. Current and futures prices for natural gas in markets that compete with North America have been higher than prices for natural gas in North America, which has adversely affected the volume of LNG imports into North America. If LNG deliveries to North America continue to be constrained due to stronger demand from these competing markets, our ability and the ability of existing and prospective third-party TUA customers to import LNG into North America on a profitable basis may be adversely affected.

Political instability in foreign countries that have supplies of natural gas, or strained relations between such countries and the U.S., may also impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the U.S. Furthermore, some foreign suppliers of LNG may have economic or other reasons to direct their LNG to non-U.S. markets or to competitors' LNG receiving terminals in the U.S.

As a result of these and other factors, LNG may not be a competitive source of energy in North America. The failure of LNG to be a competitive supply alternative to domestic natural gas, oil and other alternative energy sources could adversely affect our ability to enter into additional TUAs with customers , which could inhibit our growth and cause us operating losses. Any significant impediment to the ability to import LNG into the United States generally or to the Sabine Pass LNG terminal specifically could have a material adverse effect on us, our customers and on our business, results of operations, financial condition and prospects.

The inability to import LNG into the U.S. may also limit the LNG assets being constructed and, therefore, our potential acquisition opportunities, which may limit our ability to increase distributions to our unitholders.

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 customers and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

The development of domestic LNG receiving terminals 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 customers and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Cyclical or other changes in the demand for LNG capacity may adversely affect our 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 or liquefaction services 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 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.

Our business faces competition, including competing LNG terminals, from competitors with far greater resources.

Many competing companies have secured access to, or are pursuing development or acquisition of, LNG facilities to serve the North American natural gas market, including other proposed liquefaction facilities in North America. Competitors faced by our business in North America include major energy corporations. In addition, competitors have developed or reopened additional LNG terminals in Europe, Asia and other markets, which also compete with the Sabine Pass LNG terminal and our proposed liquefaction facilities. We may also face competition from major energy companies and others in pursuing our proposed business strategy to provide liquefaction and export services at the Sabine Pass LNG terminal. Almost all of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to natural gas and LNG supplies than we and our affiliates do. The superior resources that these competitors have available for deployment could allow them to compete successfully against our LNG businesses, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Insufficient development of additional LNG liquefaction and regasification capacity worldwide could adversely affect our LNG businesses and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Commercial development of an LNG facility, including our proposed expansion of the Sabine Pass LNG terminal to add bi-directional service, takes a number of years and requires substantial capital investment. Many factors could negatively affect continued development of LNG facilities, including:


•	increased construction costs;


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


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


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


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


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

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

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


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


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


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


•	work stoppages or other labor disturbances at the shipyards;


•	bankruptcy or other financial crisis of shipbuilders;


•	quality or engineering problems;


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


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

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 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 2011 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.

Terrorist attacks or military campaigns may adversely impact our business.

A terrorist or military incident may 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 TUA customers including their ability to satisfy their obligations to us under their TUAs.

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;


•	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 receiving 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 million of Senior Notes that mature in 2013 and $1,666.0 million of Senior Notes that mature in 2016. 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.

Sabine Pass LNG may be restricted under the terms of the Sabine Pass Indenture from making distributions to us and from incurring additional indebtedness 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 of, or premium, if any, 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 to us. 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 to us 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. As discussed above under “-Risks Relating to Our Business-We may be unable to commercially exploit the capacity at the Sabine Pass LNG terminal that we have reserved for our own account,” Cheniere Investments has not commercialized its reserved regasification capacity and may have difficulty making its TUA payments.

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 us 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 any other agreements. Cheniere Marketing is further obligated to make payments to us to the extent that we have a shortfall between our available cash and initial quarterly distributions to our common unitholders.

In addition, even if Sabine Pass LNG receives the contracted payments under the Cheniere Investments TUA, the fixed charge coverage test will not be satisfied if those payments do not constitute revenues under U.S. generally accepted accounting principles, or GAAP, as then in effect and as provided in the Sabine Pass Indenture. Because the Cheniere Investments TUA is an agreement between related parties, payments under the Cheniere Investments TUA may not constitute revenues under GAAP as currently in effect if Cheniere Investments is determined to lack economic substance apart from Sabine Pass LNG. We believe Cheniere Investments could be determined to lack economic substance apart from Sabine Pass LNG if, for example, Cheniere Investments has no substantive business and is not pursuing, and has no prospect of developing, any substantive business apart from its TUA with Sabine Pass LNG.

If we do not receive distributions from Sabine Pass LNG, 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 will pay significant management fees to our general partner and its affiliates and reimburse them for expenses incurred on our behalf, which will reduce 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


•	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 did not pay 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 the proposed liquefaction facilities, that would result in sufficient cash flow to fully pay distributions to the subordinated unitholders and allow us to increase common unit holder 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 outside the United States could expose us to political, governmental and economic instability and effects of foreign currency exchange fluctuations on our counterparties.

Agreements with counterparties outside 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 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.

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.

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.

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 82% 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 41.23% of our total common units. If the subordinated units convert into common units, affiliates of our general partner will own approximately 90.4% 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.

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, or the 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.

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 10,891,357 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.

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, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Section 7704(d) of the Internal Revenue Code. It is possible that these legislative efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the most recently proposed legislation would not appear to affect our tax treatment as a partnership, 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 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.

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 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) 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.

The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the technical termination occurs.

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.

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, 2010, 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. (REMOVED AND RESERVED)

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, 2010	$	16.38	$	13.28	$	0.425	$	0.425
June 30, 2010	19.10		14.14		0.425		—
September 30, 2010	19.09		16.16		0.425		—
December 31, 2010	21.31		18.69		0.425		—

Three Months Ended
March 31, 2009	7.10		4.32		0.425		0.425
June 30, 2009	7.99		6.03		0.425		0.425
September 30, 2009	9.95		6.95		0.425		0.425
December 31, 2009	13.30		9.27		0.425		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, 2010 of $0.425 per common unit was paid on February 14, 2011. In addition, we paid cash distributions to our general partner with respect to its 2% general partner interest.

As of February 21, 2011, we had 26,421,023 common units outstanding held by approximately 11 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.

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 83.7% 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 did not pay any distributions on our subordinated units with respect to the quarters ended June 30, 2010, September 30, 2010 and December 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.

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
	Total Quarterly Distribution Target Amount	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%

ITEM 6. SELECTED FINANCIAL DATA

The following tables set forth the selected financial data of our combined predecessor entities for the periods and at the dates indicated. Our combined predecessor entities refer to us and our wholly owned subsidiaries, including Sabine Pass LNG.

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 Notes thereto included elsewhere in this report.



	Cheniere Energy Partners, L.P.												Combined Predecessor Entities
	December 31,
	2010			2009			2008			2007			2006
	(in thousands)
Statement of Operations Data:
Revenues (including transactions with affiliates)	$	399,282		$	416,790		$	15,000		$	—		$	—
Expenses (including transactions with affiliates)	118,485			88,870			32,141			12,516			10,277
Income (loss) from operations	280,797			327,920			(17,141		)	(12,516		)	(10,277		)
Other income (expense) (1)	(173,229		)	(141,008		)	(61,203		)	(36,436		)	(50,495		)
Net income (loss)	107,568			186,912			(78,344		)	(48,952		)	(60,772		)

Cash Flow Data:
Cash flows provided by (used in) operating activities	104,137			234,311			(1,156		)	(640		)	(27,912		)
Cash flows provided by (used in) investing activities	(5,076		)	92,146			(560		)	(74,776		)	(1,544,408		)
Cash flows provided by (used in) financing activities	(163,254		)	(208,922		)	1,710			75,422			1,572,222

	Cheniere Energy Partners, L.P.												Combined Predecessor Entities
	December 31,
	2010			2009			2008			2007			2006
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	53,349		$	117,542		$	7		$	13		$	7
Restricted cash and cash equivalents (current)	13,732			13,732			235,985			191,179			176,324
Non-current restricted cash and cash equivalents	82,394			82,394			137,984			453,843			982,613
Non-current restricted U.S. Treasury securities	—			—			20,829			63,923			—
Property, plant and equipment, net	1,550,465			1,588,557			1,517,507			1,127,289			651,676
Total assets	1,743,492			1,859,473			1,978,835			1,904,978			1,858,114
Long-term debt	2,187,724			2,110,101			2,107,673			2,032,000			2,032,000
Long-term debt—related party	—			72,928			70,661			—			—
Long-term debt—affiliate	—			—			2,372			645			—
Deferred revenue (long-term)	29,500			33,500			37,500			40,000			40,000
Deferred revenue—affiliate (long-term)	9,813			7,360			4,971			2,583			—


(1)	The year ended December 31, 2006 includes a $23.8 million loss related to the extinguishment of debt issuance costs and a $20.6 million derivative loss as a result of terminating interest rate swaps, both related to the termination of a Sabine Pass credit facility in November 2006.

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. 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 includes the following subjects:


•	Overview of Business


•	Overview of Significant 2010 Events


•	Liquidity and Capital Resources


•	Contractual Obligations


•	Results of Operations


•	Off-Balance Sheet Arrangements


•	Summary of Critical Accounting Policies


•	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.

Following the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008, Sabine Pass LNG began receiving capacity reservation fee payments from Cheniere Marketing, LLC (“Cheniere Marketing”), a wholly owned subsidiary of Cheniere, under its Terminal Use Agreement ("TUA"). In December 2008, Cheniere Marketing began paying Sabine Pass LNG its monthly capacity reservation fee payment on a quarterly basis. Sabine Pass LNG also began receiving monthly capacity reservation fee payments from Total Gas and Power North America, Inc. (“Total”) and Chevron U.S.A., Inc. (“Chevron”) under their TUAs in March 2009 and June 2009, respectively.

In June 2010, Cheniere Marketing assigned its TUA with Sabine Pass LNG to Cheniere Energy Investments, LLC (“Cheniere Investments”), our wholly owned subsidiary, effective July 1, 2010. Concurrently, Cheniere Investments entered into a Variable Capacity Rights Agreement (“VCRA”), described below, with Cheniere Marketing in order for Cheniere Investments to monetize its TUA capacity at the Sabine Pass LNG terminal in exchange for compensation based upon the profitability of each transaction undertaken by Cheniere Marketing.

LNG Terminal Business

The Sabine Pass LNG terminal has regasification capacity of approximately 4.0 billion cubic feet per day (“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. Construction of the Sabine Pass LNG terminal commenced in March 2005. We achieved full operability during the third quarter of 2009 with total sendout capacity of approximately 4.0 Bcf/d (with peak capacity of approximately 4.3 Bcf/d) and aggregate storage capacity of approximately 16.9 Bcf.

Overview of Significant 2010 Events

In 2010, 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. The major events of 2010 include the following:


•	In June 2010, we initiated a project to add liquefaction services at the Sabine Pass LNG terminal, which would transform the terminal into a bi-directional facility capable of liquefying natural gas and exporting LNG in addition to importing and regasifying foreign-sourced LNG.

•

In June 2010, Cheniere Marketing assigned its TUA with Sabine Pass LNG to Cheniere Investments, effective July 1, 2010, and concurrently entered into the VCRA with Cheniere Investments. Under the terms of the VCRA, Cheniere Marketing was contracted by Cheniere Investments to monetize the regasification capacity at the Sabine Pass LNG terminal on its behalf in exchange for compensation based upon the profitability of each transaction undertaken by Cheniere Marketing.

•

In September 2010, Sabine Pass Liquefaction, LLC ("Sabine Liquefaction"), our wholly owned subsidiary, received approval from the U.S. Department of Energy ("DOE") to export 16.0 mtpa of LNG produced from domestic natural gas for over thirty years starting not later than September 2020. This license authorizes Sabine Liquefaction to export LNG to purchasers in countries which have a Free Trade Agreement ("FTA") with the U.S. A second application was filed with the DOE requesting to expand the permit for a 20-year period and to allow export to countries with which the U.S. does not have an FTA.

Liquidity and Capital Resources

Cash and Cash Equivalents

As of December 31, 2010, we had $53.3 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 are anticipated to be sufficient to fund operating expenditures and interest requirements. 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 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 Sabine Pass 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 the liquefaction project.

TUA Revenues

The entire approximately 4.0 Bcf/d of regasification capacity at the Sabine Pass LNG receiving terminal has been fully reserved under three 20-year, firm commitment TUAs. 2.0 Bcf/d is contracted with unaffiliated third parties and 2.0 Bcf/d is contracted with Cheniere Investments. Each of the three customers at the Sabine Pass LNG terminal must make the full contracted amount of capacity reservation fee payments under its TUA whether or not it uses any of its reserved capacity. Capacity reservation fee TUA payments are made by Sabine Pass LNG's third-party customers as follows:


•	Total has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions; and


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

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 required to make capacity payments 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 required to make capacity payments 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.

Concurrent with the TUA assignment, Cheniere Investments entered into a 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 two years, or (d) the termination of the VCRA as a result of default. Prior to 2018, Cheniere Marketing's termination right is subject to Cheniere Partners having specified levels of cash reserved for distribution to its common unitholders as of the applicable termination date. Under the terms of the VCRA, Cheniere Marketing will be responsible for monetizing the capacity at the Sabine Pass LNG terminal held by Cheniere Investments and will have 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 Project

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, 2010, 2009 and 2008. 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,
	2010			2009			2008
Sources of cash and cash equivalents
Use of restricted cash and cash equivalents	$	—		$	298,673		$	426,592
Operating cash flow	104,137			234,311			—
Proceeds from issuance of debt	—			—			144,965
Borrowings under long-term note—affiliate	—			114			1,708
Affiliate payable	—			—			1
Total sources of cash and cash equivalents	104,137			533,098			573,266

Uses of cash and cash equivalents
LNG terminal construction-in-process, net	(4,955		)	(96,918		)	(402,955		)
Distributions to owners	(163,249		)	(280,675		)	(45,824		)
Advances under long-term contracts	(121		)	(601		)	(14,274		)
Repayment of long-term note—affiliate	—			(2,467		)	—
Advances to affiliate—LNG held for commissioning, net of amounts transferred to LNG terminal construction-in-process	—			—			(9,923		)
Debt issuance costs	—			(23		)	(4,837		)
Operating cash flow	—			—			(1,156		)
Special rights adjustment	—			(34,879		)	—
Investments in restricted cash and cash equivalents	—			—			(94,303		)
Other	(5		)	—			—
Total uses of cash and cash equivalents	(168,330		)	(415,563		)	(573,272		)

Net increase (decrease) in cash and cash equivalents	(64,193		)	117,535			(6		)
Cash and cash equivalents—beginning of year	117,542			7			13
Cash and cah equivalents—end of year	$	53,349		$	117,542		$	7

Use of restricted cash and cash equivalents

In 2010, 2009 and 2008, zero, $298.7 million and $426.6 million of restricted cash and cash equivalents, respectively, were primarily used to pay for construction activities at the Sabine Pass LNG terminal. Under the Sabine Pass Indenture governing the Senior Notes, 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 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 decreased use of restricted cash and cash equivalents in 2009 and 2010 primarily resulted from completing construction of the initial sendout capacity of approximately 2.6 Bcf/d and storage capacity of approximately 10.1 Bcf at the Sabine Pass LNG terminal in September 2008, and the substantial completion of the Sabine Pass LNG terminal’s construction activities during the third quarter 2009.

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 the proposed liquefaction project.

In 2009, Sabine Pass LNG received capacity reservation fee payments from Cheniere Marketing of approximately $250 million, and received capacity reservation fee payments from Total and Chevron of approximately $177 million. These operating cash flows were offset by interest expense, operating and maintenance costs and general and administrative costs.

In September 2008, Sabine Pass LNG received $15.0 million from Cheniere Marketing related to prepaid capacity reservation fee payments for the last three months of 2008. In addition, Sabine Pass LNG received $62.7 million in December 2008 from Cheniere Marketing related to prepaid capacity reservation fee payments for the first three months of 2009. These operating cash flows were offset by interest expense, operating and maintenance costs and general and administrative costs.

Proceeds from issuance of debt

Proceeds from issuance of debt were $145.0 million in 2008. The $145.0 million in borrowings during 2008 related to the additional issuance of 2016 Notes, net of discount.

Proceeds from issuance of common units

Proceeds from issuance of common units of $98.4 million relate to the 2007 issuance of 5.1 million of our common units at an initial public offering price of $21.00 per common unit, net of underwriting discounts and commissions of $7.2 million and a structuring fee of $0.5 million. We used all of the net proceeds we received to purchase U.S. Treasury securities to fund a distribution reserve for payment of the initial quarterly distributions through distributions made with respect to the quarter ended June 30, 2009.

LNG terminal construction-in-process, net

Capital expenditures for the Sabine Pass LNG terminal were $5.0 million, $96.9 million and $403.0 million in 2010, 2009 and 2008, respectively. Our capital expenditures decreased in 2010 and 2009 as a result of the substantial completion of the construction of the Sabine Pass LNG terminal in the third quarter of 2009. Our capital expenditures decreased in 2008 as a result of the winding down and completion of construction of the initial phases of the Sabine Pass LNG terminal.

Distributions to owners

We made $163.2 million and $280.7 million of distributions to our common and subordinated unitholders and to our general partner in 2010 and 2009, respectively. We made $45.8 million of distributions to common unitholders and to our general partner in 2008. The decreased distributions to owners in 2010 compared to 2009 is a result of the TUA assignment from Cheniere Marketing to Cheniere Investments, effective July 1, 2010, that decreased our available cash in excess of the common unit and general partner distributions. As a result, we have not paid any distributions on our subordinated units with respect to the quarters ended on or after June 30, 2010. The increased distributions to owners in 2009 compared to 2008 is a result of Sabine Pass LNG receiving a full year of capacity reservation fee payments from Cheniere Marketing, and beginning to receive capacity reservation fee payments from Total and Chevron in 2009.

Advances under long-term contracts

Sabine Pass LNG entered into certain contracts and purchase agreements related to the construction of the Sabine Pass LNG terminal that required Sabine Pass LNG to make payments to fund costs that will be incurred or equipment that will be received in the future. Advances made under long-term contracts on purchase commitments are carried at face value and transferred to property, plant, and equipment as the costs are incurred or equipment is received. Advances under long-term contracts were $0.1 million, $0.6 million and $14.3 million in 2010, 2009 and 2008, respectively. The decrease in 2010 and 2009 compared to 2008 resulted from substantially completing construction of the Sabine Pass LNG terminal in the third quarter of 2009. During 2009, the Sabine Pass LNG terminal received equipment that it had previously advanced payment for under long-term contracts.

Advances to affiliate—LNG held for commissioning, net of amounts transferred to LNG terminal construction-in-process

During 2008, we advanced $9.9 million for LNG commissioning cargoes, net of amounts transferred to LNG terminal construction-in-process.

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.

Investments in restricted cash and cash equivalents

Investments in restricted cash and cash equivalents were $94.3 million in 2008. Investments in restricted cash and cash equivalents are cash and cash equivalents that have been contractually restricted to be used for a specific purpose. The 2008 investments in restricted cash and cash equivalents were related to borrowings that were contractually restricted to be used in the construction of the Sabine Pass LNG terminal, interest payments on the Senior Notes and establishment of a distribution reserve account pursuant to 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. 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, 2010:



				Total Distribution (in thousands)
Date Paid	Period Covered by Distribution	Distribution Per Common Unit		Common and General Partner Units		Subordinated Units
February 12, 2010	October 1 – December 31, 2009	$	0.425	$	12,630	$	57,538
May 14, 2010	January 1 – March 31, 2010	0.425		12,630		57,538
August 13, 2010	April 1 – June 30, 2010	0.425		11,456		—
November 12, 2010	July 1, 2009 – September 30, 2010	0.425		11,456		—

Pursuant to our partnership agreement, 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 ending on or after June 30, 2010, when certain conditions that are defined in our partnership agreement are met.

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. 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 June 30, 2010, September 30, 2010 and December 31, 2010. The subordinated units will receive distributions only to the extent we have available cash above the minimum quarterly distributions requirement for our common unitholders and general partner along with certain reserves. Such available cash could be generated through new business development or fees received from Cheniere Marketing under the VCRA. The ending of the subordination period and conversion of the subordinated units into common units will depend upon future business development and is no longer expected to occur as early as previously estimated.

Debt Agreements

Senior Notes

Sabine Pass LNG has issued an aggregate principal amount of $2,215.5 million of Senior Notes (the "Senior Notes"), consisting of $550.0 million of 7¼% Senior Secured Notes due 2013 (the "2013 Notes") and $1,665.5 million of 7½% Senior Secured Notes due 2016 (the "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. Under the Sabine Pass Indenture governing the Senior Notes, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment 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 year ended December 31, 2010, Sabine Pass LNG made distributions of $374.8 million to us after satisfying all of the applicable conditions in the Sabine Pass Indenture.

Services Agreements

During the 2010, 2009 and 2008, we paid an aggregate of $15.9 million, $18.5 million and $5.2 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. For further description of the O&M Agreement, see Note 12—"Related Party Transactions" of our Notes to Consolidated Financial Statements.

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). For further description of the MSA, see Note 12—"Related Party Transactions" of our Notes to Consolidated Financial Statements.

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 reimbursed Cheniere Terminals for its services in an amount equal to the sum of all out-of-pocket costs and expenses incurred by Cheniere Terminals 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 regasification capacity held by Cheniere Investments and develop new projects through either internal development or acquisition to increase cash flow. For further description of the Cheniere Partners services agreement, see Note 12—"Related Party Transactions" of our Notes to Consolidated Financial Statements.

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, 2010 (in thousands).



	Payments Due for Years Ended December 31,
	Total		2011		2012 - 2013		2014 - 2015		Thereafter
Operating lease obligations (1) (2)	$	267,346	$	8,988	$	17,836	$	17,836	$	222,686
Long-term debt (excluding interest) (3)	2,215,500		—		550,000		—		1,665,500
Service contracts:
Affiliate O&M Agreement (4)	22,100		1,560		3,120		3,120		14,300
Affiliate Sabine Pass LNG MSA (4)	88,400		6,240		12,480		12,480		57,200
Affiliate services agreement (4)	180,000		10,000		20,000		20,000		130,000
Construction and purchase obligations (4)	3,168		3,084		84		—		—
Cooperative endeavor agreements (4)	14,720		2,453		4,907		4,907		2,453
Other obligation (5)	1,500		750		750		—		—
Total	$	2,792,734	$	33,075	$	609,177	$	58,343	$	2,092,139


(1)	A discussion of these obligations can be found in Note 13—“Leases” of our Consolidated Financial Statements.


(2)	Minimum lease payments have not been reduced by a minimum sublease rental of $123.0 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, 2010, our cash payments for interest would be $164.8 million in 2011, $164.8 million in 2012, $161.5 million in 2013, $124.9 million in 2014, $124.9 million in 2015 and $114.5 million for the remaining years for a total of $855.4 million. See Note 10—“Long-Term Debt (including related party)" of our Consolidated Financial Statements.


(4)	A discussion of these obligations can be found in Note 12—“Related Party Transactions” of our Consolidated Financial Statements.


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

Results of Operations

Overall Operations

2010 vs. 2009

Our consolidated net income decreased $79.3 million, from $186.9 million in 2009 to $107.6 million in 2010. This $79.3 million decrease in net income in 2010 primarily resulted from the TUA assignment from Cheniere Marketing to Investments effective July 1, 2010. Beginning July 1, 2010, our revenues-affiliate reflects only tug service revenue and the amount of income earned under the VCRA from Cheniere Marketing because the affiliate revenue earned by Sabine Pass LNG from 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.

2009 vs. 2008

Our consolidated net income increased $265.2 million, from a $78.3 million net loss in 2008 to net income of $186.9 million in 2009. This $265.2 million increase in net income in 2009 resulted from the commencement of revenues under the Cheniere Marketing TUA beginning on October 1, 2008, the Total TUA beginning on April 1, 2009 and the Chevron TUA beginning on July 1, 2009.

Revenues (including Affiliate Revenues)

2010 vs. 2009

Total revenues decreased $17.5 million, from $416.8 million in 2009 to $399.3 million in 2010. This decrease primarily resulted from a decrease in affiliate revenues resulting from the TUA assignment from Cheniere Marketing to Investments as discussed above, 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.

2009 vs. 2008

Our revenues increased $163.9 million, from zero in 2008 to $163.9 million in 2009. This $163.9 million increase primarily resulted from the commencement of revenues under the Total TUA beginning on April 1, 2009 and the Chevron TUA beginning on July 1, 2009. Our revenues-affiliate increased $237.9 million, from $15.0 million in 2008 to $252.9 million in 2009. Cheniere Marketing is required to make capacity reservation fee payments aggregating approximately $250 million per year for the period from January 1, 2009 through at least September 30, 2028. Following the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008, Cheniere Marketing made a capacity payment of $15.0 million for October, November and December of 2008.

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.

2009 vs. 2008

Interest expense, net of amounts capitalized, increased $67.3 million, from $79.9 million in 2008 to $147.2 million in 2009. This increase in interest expense, net of amount capitalized, primarily resulted from the additional $183.5 million, before discount, of 2016 Notes issued in September 2008, and a decrease in interest expense subject to capitalization in 2009 compared to 2008 due to the costs associated with placing the initial 2.6 Bcf/d of sendout capacity and 10.1 Bcf of storage capacity of the Sabine Pass LNG terminal into service in September 2008 and the substantial completion of construction and achievement of full operability of the Sabine Pass LNG terminal, with approximately 4.0 Bcf/d of total sendout capacity and five LNG storage tanks with approximately 16.9 Bcf of aggregate storage capacity, in the third quarter of 2009.

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 beginning to depreciate the costs associated with the achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009.

2009 vs. 2008

Depreciation expense increased $24.7 million, from $8.0 million in 2008 to $32.7 million in 2009. This $24.7 million increase in depreciation expense was primarily related to beginning depreciation on the costs associated with the initial 2.6 Bcf/d of sendout capacity and 10.1 Bcf of storage capacity of the Sabine Pass LNG terminal that was placed into service in the third quarter of 2008. In addition, depreciation expense increased in 2009 as a result of the substantial completion of construction and achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009 as described above.

Operating and Maintenance Expense (including Affiliate Expense)

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 the entire year of 2010, as compared to only a portion of 2009.

2009 vs. 2008

Operating and maintenance expense (including affiliate expense) increased $21.0 million, from $11.5 million in 2008 to $32.5 million in 2009. This $21.0 million increase resulted from the achievement of commercial operability of the initial 2.6 Bcf/d of sendout capacity and 10.1 Bcf of storage capacity of the Sabine Pass LNG terminal in the third quarter of 2008 and the substantial completion of construction and achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009 as described above.

Development Expense (including Affiliate Expense)

Development expense (including affiliate expense) increased $10.5 million, from zero in 2009 to $10.5 million in 2010. This increase resulted from costs incurred to develop the liquefaction project at the Sabine Pass LNG receiving terminal.

General and Administrative Expense (including Affiliate Expense)

2009 vs. 2008

General and administrative expense (including affiliate expense) increased $13.3 million, from $10.3 million in 2008 to $23.6 million in 2009. This increase primarily related to an increase in the amount of service agreement charges due to the achievement of substantial completion of construction and achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009 and due to the commencement of the services agreement with Cheniere Terminals on January 1, 2009.

Interest Income

2009 vs. 2008

Interest income decreased $12.9 million, from $13.8 million in 2008 to $0.9 million in 2009. This decrease resulted from less restricted cash and cash equivalents invested and lower interest rates during 2009 compared to 2008.

Off-Balance Sheet Arrangements

As of December 31, 2010, 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

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 U.S. generally accepted accounting principles (“GAAP”), we endeavor to comply properly 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.

Accounting for LNG Activities

Generally, expenditures for direct 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.

We capitalized interest and other related debt costs during the construction period of the Sabine Pass LNG terminal. Upon commencement of operations, capitalized interest, as a component of the total cost, has been 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 revenue as Sabine Pass LNG performs the services set forth in each customer’s TUA.

Cash Flow Hedges

We have used, and may in the future use, derivative instruments to limit our exposure to variability in expected future cash flows. Cash flow hedge transactions hedge the exposure to variability in expected future cash flows. In the case of cash flow hedges, the hedged item (the underlying risk) is generally unrecognized (i.e., not recorded on the consolidated balance sheet prior to settlement), and any changes in the fair value, therefore, will not be recorded within earnings. Conceptually, if a cash flow hedge is effective, this means that a variable, such as a movement in interest rates, has been effectively fixed so that any fluctuations will have no net result on either cash flows or earnings. Therefore, if the changes in fair value of the hedged item are not recorded in earnings, then the changes in fair value of the hedging instrument (the derivative) must also be excluded from the income statement or else a one-sided net impact on earnings will be reported, despite the fact that the establishment of the effective hedge results in no net economic impact. To prevent such a scenario from occurring, GAAP requires that the fair value of a derivative instrument designated as a cash flow hedge be recorded as an asset or liability on the balance sheet, but with the offset reported as part of other comprehensive income, to the extent that the hedge is effective. We assess, both at the inception of each hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. On an on-going basis, we monitor the actual dollar offset of the hedges’ market values compared to hypothetical cash flow hedges. Any ineffective portion of the cash flow hedges will be reflected in earnings. Ineffectiveness is the amount of gains or losses from derivative instruments that are not offset by corresponding and opposite gains or losses on the expected future transaction.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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 our estimates and assumptions used.

Items subject to estimates and assumptions include, but are not limited to, the carrying amount of property, plant and equipment. Actual results could differ significantly from those estimates.

Recent Accounting Standards

In January 2010, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance which requires additional disclosures and clarifies certain existing disclosure requirements regarding fair value measurements. This guidance is effective for interim and annual reporting periods beginning after December 15, 2009. We adopted this guidance effective January 1, 2010. However, none of the specific additional disclosure requirements were applicable to us at the time of filing this report. (See Note 7—“Financial Instruments” of our Notes to Consolidated Financial Statements for our fair value measurement disclosures.)

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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

CHENIERE ENERGY PARTNERS, L.P.



Management’s Report to the Unitholders of Cheniere Energy Partners, L.P.	47
Reports of Independent Registered Public Accounting Firm—Ernst & Young LLP	48
Consolidated Balance Sheets	51
Consolidated Statements of Operations	52
Consolidated Statements of Partners’ and Owners’ Capital (Deficit)	53
Consolidated Statements of Cash Flows	54
Notes to Consolidated Financial Statements	55
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data	70

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”). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.

Based on our assessment, we have concluded that Cheniere Partners' internal control over financial reporting was not effective as a result of the material weakness related to the presentation of basic and diluted net income (loss) per common unit, as of December 31, 2010, 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, 2010. The report of our independent registered public accounting firm is contained in this Amendment No. 1 on Form 10-K/A to our annual report for the year ended December 31, 2010.

Management’s Certifications

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



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 and Accounting Officer)

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, 2010 and 2009, 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, 2010. 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, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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.

As discussed in Note 16, the consolidated financial statements have been restated to present net income (loss) per common unit.

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, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 2, 2011 (except for the effect of the material weakness described in the sixth paragraph of that report, as to which the date is September 12, 2011) expressed an adverse opinion thereon.

/s/ ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

March 2, 2011 except as to the presentation of basic and diluted

net income (loss) per common unit discussed in Note 16

as to which the date is September 12, 2011

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' (the Company) internal control over financial reporting as of December 31, 2010, 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 report dated March 2, 2011, we expressed an unqualified opinion that Cheniere Energy Partners, L.P. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria. Management has subsequently determined that a deficiency in controls related to the presentation of basic and diluted net income (loss) per common unit existed as of the previous assessment date, and has further concluded that such deficiency represented a material weakness as of December 31, 2010. As a result, management has revised its assessment, as presented in the accompanying Management's Report on Internal Control Over Financial Reporting; to conclude that Cheniere Energy Partners, L.P. and subsidiaries internal control over financial reporting was not effective as of December 31, 2010. Accordingly, our present opinion on the effectiveness of the Cheniere Energy Partners, L.P. and subsidiaries internal control over financial reporting as of December 31, 2010, as expressed herein, is different from that expressed in our previous report.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management's assessment. Management has identified a material weakness in controls related to the Company's presentation of basic and diluted net income (loss) per common unit. 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, 2010 and 2009, 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, 2010. This material weakness was considered in determining the nature, timing and extent of audit tests applied in our audit of the 2010 consolidated financial statements, and this report does not affect our report dated March 2, 2011 (except as to the presentation of basic and diluted net income (loss) per common unit discussed in Note 16 as to which the date is September 12, 2011), which expressed an unqualified opinion on those financial statements.

In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Cheniere Energy Partners, L.P. has not maintained effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.

/s/ ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

March 2, 2011, except for the effect of the material weakness described in

the sixth paragraph above, as to which the date is September 12, 2011

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)



	December 31,
	2010			2009
ASSETS
Current assets
Cash and cash equivalents	$	53,349		$	117,542
Restricted cash and cash equivalents	13,732			13,732
Accounts and interest receivable	1,378			5,037
Accounts receivable—affiliate	712			3,586
Advances to affiliate	3,543			5,358
Advances to affiliate—LNG inventory	—			1,319
LNG inventory	1,212			1,521
Prepaid expenses and other	4,727			4,836
Total current assets	78,653			152,931

Non-current restricted cash and cash equivalents	82,394			82,394
Property, plant and equipment, net	1,550,465			1,588,557
Debt issuance costs, net	22,004			26,953
Other	9,976			8,638
Total assets	$	1,743,492		$	1,859,473
LIABILITIES AND PARTNERS’ DEFICIT
Current liabilities
Accounts payable	$	1,072		$	39
Accounts payable—affiliate	—			306
Accrued liabilities	17,848			22,181
Accrued liabilities—affiliate	5,949			3,095
Deferred revenue	26,592			26,456
Deferred revenue—affiliate	673			63,507
Total current liabilities	52,134			115,584

Long-term debt, net of discount	2,187,724			2,110,101
Long-term debt—related party, net of discount	—			72,928
Deferred revenue	29,500			33,500
Deferred revenue—affiliate	9,813			7,360
Other non-current liabilities	329			327

Commitments and contingencies	—			—

Partners' deficit
Common unitholders (26,416,357 units issued and outstanding at December 31, 2010 and 2009)	(69,191		)	(41,494		)
Subordinated unitholders (135,383,831 units issued and outstanding at December 31, 2010 and 2009)	(453,896		)	(427,026		)
General partner interest (2% interest with 3,302,045 units issued and outstanding at December 31, 2010 and 2009)	(12,921		)	(11,807		)
Total partners’ deficit	(536,008		)	(480,327		)
Total liabilities and partners’ deficit	$	1,743,492		$	1,859,473

See accompanying notes to consolidated financial statements.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)



	Year Ended December 31,
	2010			2009			2008
Revenues
Revenues	$	268,328		$	163,862		$	—
Revenues—affiliate	130,954			252,928			15,000
Total revenues	399,282			416,790			15,000

Expenses
Operating and maintenance expense	27,069			20,683			6,345
Operating and maintenance expense—affiliate	12,090			11,833			5,125
Depreciation expense	42,299			32,742			7,994
Development expense	8,738			—			1,184
Development expense—affiliate	1,824			—			1,158
General and administrative expense	6,190			3,722			4,843
General and administrative expense—affiliate	20,275			19,890			5,492
Total expenses	118,485			88,870			32,141

Income (loss) from operations	280,797			327,920			(17,141		)

Other income (expense)
Interest income	326			930			13,778
Interest expense, net	(174,016		)	(147,201		)	(79,887		)
Interest expense—affiliate	—			(13		)	—
Derivative gain, net	461			5,277			4,653
Other	—			(1		)	253
Total other expense	(173,229		)	(141,008		)	(61,203		)

Net income (loss)	$	107,568		$	186,912		$	(78,344	)


Basic and diluted net income (loss) per common unit (restated)-see note 16	$	1.70		$	1.13		$	(0.48	)

Weighted average number of common units outstanding used for basic and diluted net income (loss) per common unit calculation	26,416			26,416			26,416

See accompanying notes to consolidated financial statements.

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, 2007	$	33,923		$	(254,752	)	$	(6,688	)	$	(227,517	)
2008 Net loss	(12,535		)	(64,242		)	(1,567		)	(78,344		)
2008 Distributions	(44,908		)	—			(916		)	(45,824		)
Balance, December 31, 2008	(23,520		)	(318,994		)	(9,171		)	(351,685		)

2009 Net income	29,907			153,268			3,737			186,912
2009 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		)

2010 Net income	17,211			88,206			2,151			107,568
2010 Distributions	(44,908		)	(115,076		)	(3,265		)	(163,249		)
Balance, December 31, 2010	$	(69,191	)	$	(453,896	)	$	(12,921	)	$	(536,008	)

See accompanying notes to consolidated financial statements.

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2010			2009			2008
Cash flows from operating activities
Net income (loss)	$	107,568		$	186,912		$	(78,344	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation	42,299			32,742			7,994
Amortization of debt discount	4,695			4,695			1,369
Amortization of debt issuance costs	4,863			3,818			3,984
Non-cash derivative (gain) loss	124			1,106			(1,230		)
Interest income on restricted cash and cash equivalents	—			—			(16,210		)
Use of (investment in) restricted cash and cash equivalents	—			—			(1,932		)
Changes in operating assets and liabilities:
Accounts and interest receivable	(626		)	1,526			3,498
Accounts receivable—affiliate	2,874			(3,167		)	(419		)
Accounts payable and accrued liabilities	3,035			(11,517		)	21,973
Accounts payable and accrued liabilities—affiliate	2,566			2,685			(350		)
Deferred revenue—affiliate	(62,833		)	765			65,130
Deferred revenue	(3,864		)	19,955			—
Advances to affiliate	1,815			(3,160		)