form_10k.htm


 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K
 
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
 
  For the fiscal year ended December 31, 2009
OR
 ¨
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 ¨    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 ¨    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 ¨
 
  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 ¨   No ¨
 
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  ¨
Accelerated filer  x
Non-accelerated filer  ¨
Smaller reporting company  ¨
(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  ¨    No  x
 
The aggregate market value of the registrant’s Common Units held by non-affiliates of the registrant was approximately $192,000,000 as of June 30, 2009.
 
The issuer had 26,416,357 common units and 135,383,831 subordinated units outstanding as of February 17, 2010.
 
Documents incorporated by reference: None  
 

 
 

 

CHENIERE ENERGY PARTNERS, L.P
Index to Form 10-K
 
1 
1 
1 
1 
1 
2 
4 
4 
5 
5 
7 
13 
16 
20 
23 
23 
23 
23 
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26 
27 
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28 
28 
34 
34 
36 
36 
37 
38 
39 
62 
62 
62 
63 
63 
66 
68 
70 
71 
72 
72 


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CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS
 
This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:
 
 
statements regarding our ability to pay distributions to our unitholders;
 
 
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 LNG imports into North America; sales of natural gas in North America; and the transportation, other infrastructure or prices related to natural gas, LNG or other energy sources;
 
 
statements regarding any financing transactions or arrangements, or ability to enter into such transactions or arrangements;
 
 
statements regarding any terminal use agreement (“TUA”) or other agreements to be entered into or 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 or storage capacity that are, or may become, subject to TUAs or other contracts;
 
 
statements regarding counterparties to our TUAs, construction contracts and other contracts;
 
 
statements regarding any business strategy, any business plans or any other plans, forecasts, projections or objectives, 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,” “develop,” “estimate,” “expect,” “forecast,” “plan,” “potential,” “project,” “propose,” “strategy” and similar terms and phrases. 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 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. These forward-looking statements are made as of the date of this annual report.
 

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DEFINITIONS
 
In this annual report, unless the context otherwise requires:
 
 
 
Bcf means billion cubic feet;
 
 
Bcf/d means billion cubic feet per day;
 
 
EPC means engineering, procurement and construction;
 
 
EPCM means engineering, procurement, construction and management;
 
 
LNG means liquefied natural gas; and
 
 
TUA means terminal use agreement.
 
PART I
 
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
General
 
We are a Delaware limited partnership formed by Cheniere Energy, Inc. (“Cheniere”). Through our wholly-owned subsidiary, Sabine Pass LNG, L.P. (“Sabine Pass LNG”), we own and operate the Sabine Pass LNG receiving terminal located in western Cameron Parish, Louisiana on the Sabine Pass Channel.
 
In March and April 2007, we and Cheniere LNG Holdings, LLC (“Holdings”), a wholly-owned subsidiary of Cheniere, as a selling untiholder, completed a public offering of 15,525,000 of our common units (the “Offering”). We received $98.4 million of net proceeds, after deducting the underwriting discount and structuring fees, upon issuance of 5,054,164 common units to the public in the Offering. We invested the $98.4 million of net proceeds that we received from the Offering in U.S. Treasury securities to fund a distribution reserve. As part of the Offering, Holdings, as a selling unitholder, received $203.9 million of net proceeds in connection with the sale of 10,470,836 of our common units to the public. We did not receive any proceeds from the sale of common units by Holdings. In connection with the Offering and in exchange for our common and subordinated units and the right to receive the amount, if any, remaining in a distribution reserve account, Holdings contributed to us the equity interests in the entity owning the Sabine Pass LNG receiving terminal. As a result of the Offering, Cheniere’s indirect ownership interest in us is approximately 90.6%.
 
In the second quarter of 2009, Sabine Pass LNG purchased Sabine Pass Tug Services, LLC (“Tug Services”), a wholly-owned subsidiary of Cheniere.  As a result, Sabine Pass LNG acquired a lease for the use of tug boats and marine services at the Sabine Pass LNG receiving terminal.  In connection with the acquisition, Tug Services entered into agreements with Sabine Pass LNG’s three TUA customers to provide their LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG receiving terminal.
 
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 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 receiving terminal and to 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 receiving terminal; and
 
 
expanding our existing asset base through acquisitions from Cheniere or third parties, or our own development, of complementary businesses or assets, such as other LNG receiving terminals, natural gas storage assets and pipelines.

 
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Our Business
 
Sabine Pass LNG has constructed and is now operating the Sabine Pass LNG receiving 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 receiving terminal.  Sabine Pass LNG has long-term leases for three tracts of land consisting of 853 acres in Cameron Parish, Louisiana for the project site.  The Sabine Pass LNG receiving terminal was designed, and permitted by the Federal Energy Regulatory Commission (“FERC”), with a regasification capacity of approximately 4.0 Bcf/d (with peak capacity of 4.3 Bcf/d) and aggregate LNG storage capacity of 16.9 Bcf. Construction at the Sabine Pass LNG receiving terminal was substantially completed in the third quarter of 2009.  As of December 31, 2009, Sabine Pass LNG had completed construction and attained full operability of the Sabine Pass LNG receiving terminal, and such was accomplished within our budget.

Customers
 
The entire approximately 4.0 Bcf/d of regasification capacity at the Sabine Pass LNG receiving terminal has been contracted under two 20-year, firm commitment TUAs with unaffiliated third parties, and a third TUA with Cheniere Marketing, LLC (“Cheniere Marketing”), a wholly-owned subsidiary of Cheniere.  Each of the three customers at the Sabine Pass LNG receiving 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. (formerly known as Total LNG USA, Inc.) (“Total”) has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced on 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 has agreed to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced on July 1, 2009.  Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.
 
In addition, Cheniere Marketing has reserved the remaining 2.0 Bcf/d of regasification capacity and is entitled to use any capacity not utilized by Total and Chevron.  Cheniere Marketing began making its TUA capacity reservation fee payments in the fourth quarter of 2008.  Cheniere Marketing is required to make monthly capacity payments aggregating approximately $250 million per year for the period from January 1, 2009 through at least September 30, 2028. Cheniere Marketing has a limited operating history, limited capital and no credit rating. Cheniere, which has guaranteed the obligations of Cheniere Marketing under its TUA, has a non-investment grade corporate rating.
 
Under each of these TUAs, Sabine Pass LNG is also entitled to retain 2% of the LNG delivered for the customer’s account, which Sabine Pass LNG will use primarily as fuel for revaporization and self-generated power at the Sabine Pass LNG receiving terminal.
 
Each of Total and Chevron has paid us $20.0 million in nonrefundable advance capacity reservation fees, which will be amortized over a 10-year period as a reduction of each customer’s regasification capacity reservation fees payable under its TUA.
 
Competition
 
Sabine Pass LNG currently does not experience competition for its LNG terminal capacity because the entire approximately 4.0 Bcf/d of regasification capacity that is available at the Sabine Pass LNG receiving terminal has been fully reserved under three 20-year TUAs, under which each of the terminal’s customers is generally required to pay monthly fixed capacity reservation fees whether or not it uses any of its reserved capacity.
 
If and when Sabine Pass LNG has to replace any TUAs, we will compete with North American LNG receiving terminals and their customers. In addition, to the extent we are required to obtain LNG for cool down of the Sabine Pass LNG receiving terminal, Sabine Pass LNG must compete in the world LNG market to purchase and transport cargoes of LNG. Sabine Pass LNG may purchase and transport such cargoes at costs that may result in losses upon resale of the regasified LNG.
 
Governmental Regulation
 
The Sabine Pass LNG receiving terminal operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we

 
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obtain and maintain applicable permits and other authorizations. This regulatory burden increases the cost of operating the Sabine Pass LNG receiving terminal, 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 receiving terminal, we received and are required to maintain authorization from the FERC under Section 3 of the Natural Gas Act of 1938 (“NGA”). In addition, orders from the FERC authorizing construction of an LNG receiving terminal are typically subject to specified conditions that must be satisfied throughout operation of the Sabine Pass LNG receiving terminal. Throughout the life of the Sabine Pass LNG receiving 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 receiving terminal. The EPAct amended the NGA to prohibit market manipulation.  The EPAct increased civil and criminal penalties for any violations of the NGA, the Natural Gas Policy Act of 1978 (“NGPA”) and any rules, regulations or orders of the FERC up to $1.0 million per day per violation. In accordance with the EPAct, the FERC issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud.
 
Other Federal Governmental Permits, Approvals and Consultations
 
In addition to the FERC authorization under Section 3 of the NGA, the operation of the Sabine Pass LNG receiving terminal is also subject to additional federal permits, approvals and consultations required by other federal agencies, including: Advisory Counsel 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 receiving terminal is subject to U.S. Department of Transportation siting requirements and regulations of the U.S. Coast Guard relating to facility security. Moreover, the Sabine Pass LNG receiving terminal is subject to local and state laws, rules, and regulations.
 
Environmental Regulation
 
The Sabine Pass LNG receiving terminal operations 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.
 
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)
 
CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault, on certain classes of persons who are considered to be responsible for the spill or release of a hazardous substance into the environment. Potentially liable persons include the owner or operator of the site where the release occurred and persons who disposed or arranged for the disposal of hazardous substances at the site. Under CERCLA, responsible persons may be subject to joint and several liability. Although CERCLA currently excludes petroleum, natural gas, natural gas liquids and LNG from its definition of “hazardous substances,” this exemption may be limited or modified by the U.S. Congress in the future.
 
Clean Air Act (CAA)
 
The Sabine Pass LNG receiving terminal operations 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 receiving terminal 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 would have required reporting for all fugitive emissions throughout the Sabine Pass LNG receiving terminal and

 
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would have impacted our reporting requirements; however, this section was deferred in the final rule. 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.
 
Clean Water Act (CWA)
 
The Sabine Pass LNG receiving terminal operations are also 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 receiving 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 receiving terminal operations may also 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.
 
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 receiving 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 17, 2010, Cheniere had 196 full-time employees. See Note 13—“Related Party Transactions” in our Notes to Consolidated Combined 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, formerly the NYSE Alternext US, 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, nor is it 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, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports and other information regarding issuers, like us, that file electronically with the SEC.


 
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ITEM 1A.                      RISK FACTORS
 
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates 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 operation, 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 in whole or in part at or prior to maturity.
 
As of December 31, 2009, we had $2.2 billion of indebtedness outstanding, consisting primarily of the $550.0 million of 7¼% Senior Secured Notes due 2013 (“2013 Notes”) and $1,633.0 million, net of discount, of 7½% Senior Secured Notes due 2016 (“2016 Notes” and collectively with the 2013 Notes, the “Senior Notes”). We will have to refinance, extend or otherwise satisfy, all or a portion of our indebtedness. We may not be able to refinance, extend or otherwise satisfy our indebtedness as needed, on commercially reasonable terms or at all.
 
Our substantial indebtedness could adversely affect our ability to operate our business and prevent us from satisfying or refinancing our debt obligations.
 
    Our substantial indebtedness 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 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 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 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.

If we are unsuccessful in operating our business 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 will require significant amounts of cash.
 
We will require significant 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 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.

 
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Our ability to generate needed amounts of cash is substantially dependent upon Sabine Pass LNG’s TUAs with three customers, and we will be materially and adversely affected if any customer fails to perform its TUA obligations for any reason.
 
We are dependent, for substantially all of our operating revenues and cash flows, on TUAs with Chevron and Total, each of which has agreed to pay us approximately $125 million annually, and with Cheniere Marketing, which is required to pay us approximately $250 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 any 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.
 
Cheniere Marketing continues to develop its business, has limited capital and lacks a credit rating. In addition, Cheniere, which has guaranteed Cheniere Marketing’s TUA obligations, has a non-investment grade corporate rating of CCC+ from Standard and Poor’s. Accordingly, we believe that Cheniere Marketing and Cheniere have a higher risk of being financially unable to perform their obligations under the Cheniere Marketing TUA than either Chevron or Total have with respect to their TUAs. Although each of the TUA counterparties faces a risk that it will not be able to enter into commercial arrangements for the use of its capacity at the Sabine Pass LNG receiving terminal to support the payment of its obligations under its TUA, due to negative developments in the LNG industry or for other reasons, that risk and the potential for that risk to adversely affect us are greater for Cheniere Marketing than for Total and Chevron. The principal risks attendant to Cheniere Marketing’s future ability to generate operating cash flow to support its TUA obligations include the following:
 
 
Cheniere Marketing does not have unconditional agreements or arrangements for any supplies of LNG, or for the utilization of capacity that it has contracted for under its TUA with us and may not be able to obtain such agreements or arrangements on economical terms, or at all;
 
 
Cheniere Marketing does not have unconditional commitments from customers for the purchase of the natural gas it proposes to sell from the Sabine Pass LNG receiving terminal, and it may not be able to obtain commitments or other arrangements on economical terms, or at all; and
 
 
even if Cheniere Marketing is able to arrange for supplies and transportation of LNG to the Sabine Pass LNG receiving terminal, and for transportation 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.
 
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 receiving terminals and related infrastructure, which may include vessels, pipelines and LNG storage. Cheniere Marketing’s regasification capacity at the Sabine Pass LNG receiving terminal, in particular, will be marketed in competition with existing capacity and additional future capacity offered by other LNG receiving terminals that currently exist or that may be completed or expanded in the future by Cheniere affiliates or others.
 
Any or all of these factors, as well as other risk factors that we or Cheniere Marketing may not be able to anticipate, control or mitigate, could materially and adversely affect the business, results of operations, financial condition, prospects and liquidity of Cheniere Marketing, which in turn could have a material adverse effect upon us.

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 (the “Sabine Pass Indenture”) 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    

 
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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 Sabine Pass Indenture 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 Sabine Pass Indenture 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.
  
Each customer’s TUA for capacity at the Sabine Pass LNG receiving terminal is subject to termination under certain circumstances.
 
Each of the long-term TUAs with Total, Chevron and Cheniere Marketing contains various termination rights. For example, each customer may terminate its TUA if the Sabine Pass LNG receiving 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.
 
Risks Relating to Our Business
 
Operation of our LNG receiving terminal involves significant risks.
 
Our LNG receiving 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 receiving terminal, Sabine Pass LNG may need to purchase and process LNG. The cost of such LNG may exceed our estimates, and we may not be able to acquire it at an affordable price, or at all. Furthermore, even if Sabine Pass LNG is able to acquire LNG, it may not be able to resell the regasified LNG for a profit or at all.
 
LNG storage tanks and other equipment at the Sabine Pass LNG receiving terminal must be maintained in a state of cryogenic readiness for conducting operations and to provide services under Sabine Pass LNG’s TUAs.  Sabine Pass LNG may need to acquire LNG to maintain the cryogenic readiness of its LNG receiving terminal to provide services to TUA customers. The actual cost to obtain such LNG could exceed our estimates, and the cost overrun could be significant.
 
Risks associated with acquiring LNG include the following:
 
 
Sabine Pass LNG may be unable to enter into contracts for the purchase of the LNG and may be unable to obtain vessels to deliver such LNG, on terms reasonably acceptable to it or at all;
 
 
Sabine Pass LNG may bear the commodity price risk associated with purchasing the LNG, holding it in inventory for a period of time and selling the regasified LNG; and
 
 
Sabine Pass LNG may be unable to obtain financing for the purchase and shipment of the LNG on terms that are reasonably acceptable to it or at all.
 
 

 
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The failure of Sabine Pass LNG to obtain LNG, LNG vessels or both, on economical terms, or the inability to finance the purchase of LNG for maintenance of cryogenic readiness to provide services under the TUAs, could provide our TUA customers with the opportunity to interrupt or terminate their payment under their respective TUAs. Any of these occurrences could have a material adverse effect on our business, results of operations, financial condition and prospects.
 
Sabine Pass LNG may be required to purchase natural gas to provide fuel at the Sabine Pass LNG receiving terminal, which would increase operating costs and could have a material adverse effect on our results of operations.
 
Sabine Pass LNG’s three TUAs provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG receiving 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 receiving terminal site was temporarily suspended in connection with Hurricane Katrina, as a precautionary measure. Approximately three weeks after the occurrence of Hurricane Katrina, the 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 receiving 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 receiving 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 receiving terminal or related infrastructure.  If there are changes in the global climate, storm frequency and intensity may increase; should it result in rising seas, our coastal operations would be impacted.
 
Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the operation of the Sabine Pass LNG receiving terminal could impede operations and could have a material adverse effect on us.
 
The operation of the Sabine Pass LNG receiving terminal is a highly regulated activity. 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 receiving terminal. Although we have obtained all of the necessary authorizations to operate the Sabine Pass LNG receiving terminal, such authorizations are subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed. Failure to obtain and maintain any of these approvals and permits could have a material adverse effect on our business, results of operations, financial condition and prospects.
 
We are entirely dependent on Cheniere, including employees of Cheniere and its subsidiaries, for key personnel, and a loss of key personnel could have a material adverse effect on our business.
 
As of February 15, 2010, 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 receiving terminal. We face competition for these highly skilled employees in the immediate vicinity of the Sabine Pass LNG receiving 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, Sabine Pass LNG has entered into a TUA with Cheniere Marketing, under which Cheniere Marketing will be able to derive substantial economic benefits. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand.
 
 
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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.
 
Sabine Pass LNG is 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 receiving terminal is 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 receiving terminal or damage to persons and property. In addition, operations at the Sabine Pass LNG receiving terminal 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 operation of the Sabine Pass LNG receiving terminal and require us to maintain permits and provide governmental authorities with access to the facility 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. CERCLA and similar 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 the Sabine Pass LNG receiving terminal, 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 Sabine Pass LNG’s customers, particularly Cheniere Marketing, (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 Sabine Pass LNG consumes retainage gas at the Sabine Pass LNG receiving terminal, this carbon tax may also be imposed on Sabine Pass LNG directly.
 
There have also been proposals for a mandatory cap and trade program to reduce greenhouse gas emissions. In June 2009, the U.S. House of Representatives passed a comprehensive climate change and energy bill, the American Clean Energy and Security Act, and the U.S. Senate is considering similar legislation that would, among other things, impose a nationwide cap on greenhouse gas emissions and require major sources to obtain “allowances” to meet that cap. In September 2009, the EPA promulgated a rule requiring certain emitters of greenhouse gases to monitor and report their greenhouse gas emissions to the EPA. In addition, in response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA that the EPA has authority to regulate carbon dioxide emissions under the Clean Air Act, the EPA has issued and is considering several additional proposals, including one that would require best available control technology for greenhouse gas emissions whenever certain stationary sources are built or significantly modified. In addition, two U.S. federal appeals courts have reinstated lawsuits permitting individuals, state attorneys general and others to pursue claims against major utility, coal, oil and chemical companies on the basis that those companies have created a public nuisance due to their emissions of carbon dioxide. Climate change initiatives and other efforts to reduce greenhouse gas emissions like those described above or otherwise may require additional controls on the operation of the Sabine Pass LNG receiving terminal and increased costs to implement and maintain such controls.
 
 
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Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to the Sabine Pass LNG receiving terminal through the Sabine Pass Channel, could cause additional expenditures, restrictions and delays in our business, 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.
 
Failure of imported LNG to be a competitive source of energy for North American markets could adversely affect TUA customers, particularly Cheniere Marketing, and could materially and adversely affect our business, results of operations, financial condition and prospects.
 
Operations at the Sabine Pass LNG receiving terminal will be dependent upon the ability of terminal customers to import LNG supplies into the U.S., which is primarily dependent upon LNG being a competitive source of energy in North America. In North America, due mainly to a historically abundant supply of natural gas, imported LNG has not historically been a major energy source. Our business plan is based, in part, on the belief that LNG can 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 may 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, the ability of Sabine Pass LNG’s 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 impede TUA customers’ ability to import LNG into North America on a commercial basis. Any significant impediment to the ability to import LNG into the United States generally or to the Sabine Pass LNG receiving terminal specifically could have a material adverse effect on TUA customers, particularly Cheniere Marketing, 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.
 
Cyclical or other changes in the demand for LNG regasification capacity may adversely affect the performance of TUA customers, particularly Cheniere Marketing, and could reduce our operating revenues and may cause us operating losses.
 
The utilization of the Sabine Pass LNG receiving terminal could be subject to cyclical swings, reflecting alternating periods of under-supply and over-supply of LNG importation 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 receiving terminal;
 
 
insufficient LNG liquefaction capacity worldwide;
 
 
insufficient LNG tanker capacity;
 
 
reduced demand and lower prices for natural gas;
 
 
increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
 
 
cost improvements that allow competitors to offer LNG regasification services at reduced prices;
 
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changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;
 
 
changes in regulatory, tax or other governmental policies regarding imported LNG, natural gas or alternative energy sources, which may reduce the demand for imported LNG and/or natural gas;
 
 
adverse relative demand for LNG in North America compared to other markets, which may decrease LNG imports into 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 the ability of TUA customers, including Cheniere Marketing, 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.
 
We face competition from competitors with far greater resources.
 
Many competing companies have secured access to, or are pursuing development or acquisition of, LNG import infrastructure to serve the U.S. natural gas market. Some industry analysts have predicted substantial excess LNG receiving capacity in North America for at least several years based on terminals currently in operation or under construction. Our competitors in the U.S. include major energy corporations (e.g., BG Group plc, BP plc, Chevron Corporation, ConocoPhillips and Dow Chemical). In addition, other competitors have developed or reopened additional LNG receiving terminals in Europe, Asia and other markets, which also compete with the Sabine Pass LNG receiving 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 LNG supply than we and our affiliates do. The superior resources that these competitors have available for deployment could allow them to compete successfully against us, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 
Insufficient development of additional LNG liquefaction capacity worldwide could adversely affect the performance of TUA customers, particularly Cheniere Marketing, and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 
Commercial development of an LNG liquefaction facility takes a number of years and requires substantial capital investment. Many factors could negatively affect continued development of LNG liquefaction 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 in exporting countries or local community resistance in such countries to the siting of LNG facilities due to safety, environmental or security concerns; and
 
 
any significant explosion, spill or similar incident involving an LNG liquefaction facility or LNG carrier.
 
There may be shortages of LNG vessels worldwide, which could adversely affect the performance of TUA customers, particularly Cheniere Marketing, 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 the TUA 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;
 
 
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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.
 
Decreases in the demand for and price of natural gas could lead to reduced development of LNG projects worldwide, which could adversely affect the performance of TUA customers, particularly Cheniere Marketing, 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 imported LNG. 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 international 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 performance of TUA customers, particularly Cheniere Marketing, and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.
 
We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain key personnel could adversely affect us.
 
We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to operate the Sabine Pass LNG receiving terminal and to provide TUA 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 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 receiving 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 2010 will be dependent upon one asset, the Sabine Pass LNG receiving terminal located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass LNG receiving 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 incident may result in temporary or permanent closure of existing LNG facilities, including the Sabine Pass LNG receiving terminal, which could increase our costs and decrease our cash flows, depending on the duration of the closure. Operations at the Sabine Pass LNG receiving 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

 
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lead to continued volatility in prices for natural gas that could adversely affect TUA customers, particularly Cheniere Marketing, including their ability to satisfy their obligations to us under their TUAs.
 
If we do not make acquisitions 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. We may be unable to make accretive acquisitions 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 obtain necessary governmental approvals;
 
 
we are unable to obtain financing for the acquisitions on economically acceptable terms, or at all;
 
 
we are unable to secure adequate customer commitments to use the acquired facilities; or
 
 
we are outbid by competitors.
 
If we are unable to make accretive acquisitions, 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
 
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.

 
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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 been replenished with the amount (or acceptable letters of credit or acceptable guarantees in respect of such amount) required to make the next interest payment on the Senior Notes, which amount was approximately $82.4 million as of December 31, 2009.
 
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 receiving 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 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.
 
Cheniere Marketing continues to develop its business, has limited capital and lacks a credit rating. It may never develop its business, assets or revenues sufficiently to pay its fees under its TUA. Cheniere has guaranteed 100% of the obligations of Cheniere Marketing under its TUA. Cheniere has a non-investment grade corporate rating of CCC+ from Standard & Poor’s. If Cheniere does not receive sufficient future cash flows from businesses that Cheniere is developing, Cheniere may be unable to perform its guarantee of the Cheniere Marketing TUA.
 
 
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In addition, even if Sabine Pass LNG receives the contracted payments under the Cheniere Marketing 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 Marketing TUA is an agreement between related parties, payments under the Cheniere Marketing TUA may not constitute revenues under GAAP as currently in effect if Cheniere Marketing is determined to lack economic substance apart from Sabine Pass LNG. We believe Cheniere Marketing could be determined to lack economic substance apart from Sabine Pass LNG if, for example, Cheniere Marketing 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 an administrative fee of $10.0 million per year (as adjusted for inflation) for general and administrative services for our benefit. 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 receiving 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.
 
 
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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.
 
We may not be able to increase the distributions on our common units unless we are able to make accretive acquisitions, which would require us to obtain one or more sources of funding.
 
We may not be able to increase distributions on our common units by generating additional cash flows from the Sabine Pass LNG receiving terminal because the entire capacity of the Sabine Pass LNG receiving terminal has already been reserved under fixed fee TUAs with three customers. As a result, we may need to make accretive acquisitions of additional cash-generating assets and operations in order to increase the quarterly distributions on our common units.
 
To fund acquisitions, 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 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. In particular, the currently tight 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 on terms that are acceptable to us, if at all.
 
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 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 receiving 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;
 
 
16

 

 
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 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 receiving 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 receiving 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.

 
17

 
 
    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
 

 
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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 distribution will be borne by our common unitholders;
 
 
the ratio of taxable income to distributions may increase;
 
 
the relative voting strength of each previously outstanding unit may be diminished; and
 
 
the market price of the common units may decline.
 

 
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The price of our common units may fluctuate significantly, and our unitholders could lose all or part of their investment.
 
The market price of our common units may be influenced by many factors, some of which are beyond our control, including:
 
 
our quarterly distributions;
 
 
our quarterly or annual earnings or those of other companies in our industry;
 
 
actual or potential non-performance by any customer under a TUA;
 
 
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, which sales could have an adverse impact on the trading price of the common units.
 
Sales by us or any of our existing unitholders, including Holdings, of a substantial number of our common 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. The sale 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, as well as our not being subject to a material amount of additional entity level taxation by individual states. If we were to be or become treated as a corporation for federal income tax purposes or if we were to become subject to a material amount of additional entity level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this matter.
 
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 we likely would pay state taxes as well. 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.
 
Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to a material amount of entity level taxation for federal, state or local income tax purposes. In addition, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. For example, we have become subject to a new entity level tax on the portion, if any, of our revenue generated in Texas beginning for tax reports due on or after January 1, 2008. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such tax on us by the State of Texas, or any other state, will reduce the cash available for distribution to our unitholders.
 
The tax treatment of public traded partnerships or an investment in our common units could be subject to potential legislation, judicial or administrative changes and differing interpretations, possible 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
 
 
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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.  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.

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 fist day of each month, instead of on the basis of the date a particular common unit is transferred.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first business day of each month, instead of on the basis of the date a particular unit is transferred.  The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method.  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 amount 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 contests 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 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.
 
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

 
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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 United States 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. We will initially own property or do business in Louisiana and Texas. Our unitholders will likely 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. We may own property or conduct business in other states or foreign countries in the future. 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 our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have terminated 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 termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

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 methodologies 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 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 results in audit adjustments to our unitholders’ tax returns without benefit of additional deductions.
 

 
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 ITEM 1B. UNRESOLVED STAFF COMMENTS
 
None.
 
ITEM 3. LEGAL PROCEEDINGS
 
We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2009, 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
None.
 
PART II
 
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
 
Our common units began trading on the NYSE Amex Equities (formally know as NYSE Alternext US) 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 Unit (1)
 
Three Months Ended
                 
March 31, 2008
  $ 17.39     $ 14.85     $ 0.425  
June 30, 2008
    16.14       8.69       0.425  
September 30, 2008
    10.21       6.95       0.425  
December 31, 2008
    6.98       3.71       0.425  
                         
Three Months Ended
                       
March 31, 2009
    7.10       4.32       0.425  
June 30, 2009
    7.99       6.03       0.425  
September 30, 2009
    9.95       6.95       0.425  
December 31, 2009
    13.30       9.27       0.425  
 

(1)
We also paid cash distributions to subordinated unitholders and to our general partner with respect to its 2% general partner interest.
 
A distribution for the quarter ended December 31, 2009 of $0.425 per unit was paid on February 12, 2010.
 
As of February 17, 2010, we had 26,416,357 common units outstanding held by approximately 19 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 discussed in Item 7. “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.

 
23

 
 
Subordination Period
 
During the subordination period, which commenced upon the closing of our initial public offering, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the initial quarterly distribution of $0.425 per quarter, plus any arrearages in the payment of the initial quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Cheniere owns all of the 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.
 
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 ending on or after June 30, 2010 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 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 ending on or after June 30, 2008 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 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.
 
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.

 
24

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

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

 
25

 

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 Combined Financial Statements and Notes thereto included elsewhere in this report.
 
 
Cheniere Energy Partners, L.P.
 
Combined Predecessor Entities
 
 
December 31,
 
 
2009
 
2008
 
2007
 
2006
 
2005
 
 
(in thousands)
Statement of Operations Data:
                             
Revenues (including transactions with affiliates)
$
416,790
 
$
15,000
 
$
—  
 
$
—  
 
$
—  
 
Expenses (including transactions with affiliates)
 
88,870
   
32,141
   
12,516
   
10,277
   
4,719
 
Income (loss) from operations
 
327,920
   
(17,141
)
 
(12,516
)
 
(10,277
)
 
(4,719
)
Other income (expense) (1)
 
(141,008
)
 
(61,203
)
 
(36,436
)
 
(50,495
)
 
456
 
Net income (loss)
 
186,912
   
(78,344
)
 
(48,952
)
 
(60,772
)
 
(4,263
)
                               
Cash Flow Data:
                             
Cash flows provided by (used in) operating activities
 
234,311
   
(1,156
)
 
(640
)
 
(27,912
)
 
6,319
 
Cash flows provided by (used in) investing activities
 
92,146
   
(560
)
 
(74,776
)
 
(1,544,408
)
 
(246,337
)
Cash flows provided by (used in) financing activities
 
(208,922
)
 
1,710
   
75,422
   
1,572,222
   
218,201
 
 
 
Cheniere Energy Partners, L.P.
 
Combined Predecessor Entities
 
 
December 31,
 
 
2009
 
2008
 
2007
 
2006
 
2005
 
 
(in thousands)
Balance Sheet Data:
                             
Cash and cash equivalents
$
117,542 
 
$
7
 
$
13
 
$
7
 
$
5
 
Restricted cash and cash equivalents (current)
 
13,732
   
235,985
   
191,179
   
176,324
   
8,871
 
Non-current restricted cash and cash equivalents
 
82,394
   
137,984
   
453,843
   
982,613
   
—  
 
Non-current restricted U.S. Treasury securities
 
   
20,829
   
63,923
   
—  
   
—  
 
Property, plant and equipment, net
 
1,588,557
   
1,517,507
   
1,127,289
   
651,676
   
270,740
 
Total assets
 
1,859,473
   
1,978,835
   
1,904,978
   
1,858,114
   
309,139
 
Long-term debt
 
2,110,101
   
2,107,673
   
2,032,000
   
2,032,000
   
72,485
 
Long-term debt—related party
 
72,928
   
70,661
   
—  
   
—  
   
—  
 
Long-term debt—affiliate
 
   
2,372
   
645
   
—  
   
—  
 
Deferred revenue (long-term)
 
33,500
   
37,500
   
40,000
   
40,000
   
40,000
 
Deferred revenue—affiliate (long-term)
 
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 the Sabine Pass credit facility in November 2006.
 
 
 
26

 

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 2009 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. Through our wholly-owned subsidiary, Sabine Pass LNG, L.P. (“Sabine Pass LNG”), we own and operate the Sabine Pass LNG receiving terminal located in western Cameron Parish, Louisiana on the Sabine Pass Channel.
 
Following the achievement of commercial operability of the Sabine Pass LNG receiving 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 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 capacity reservation fee payments from Total Gas and Power North America, Inc. (formerly known as Total LNG USA, Inc.) (“Total”) and Chevron U.S.A., Inc. (“Chevron”) under their TUAs in March 2009 and June 2009, respectively, when Total and Chevron made their first monthly capacity reservation fee payments.
 
LNG Receiving Terminal Business
 
The Sabine Pass LNG receiving terminal has regasification capacity of approximately 4.0 Bcf/d and five liquefied natural gas (“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 receiving terminal commenced in March 2005.  We achieved full operability with total sendout capacity of approximately 4.0 Bcf/d and storage capacity of approximately 16.9 Bcf during the third quarter of 2009.

In the second quarter of 2009, Sabine Pass LNG purchased Sabine Pass Tug Services, LLC (“Tug Services”), a wholly-owned subsidiary of Cheniere. As a result, Sabine Pass LNG acquired a lease (the “Tug Agreement”) for the use of tug boats and marine services at the Sabine Pass LNG receiving terminal (see Note 14—“Leases” for further information on the Tug Agreement). In connection with this acquisition, Tug Services entered into a Terminal Marine Services Agreement (the “Tug Sharing Agreement”) with our three TUA customers to provide their LNG cargo vessels with tug boat and marine services at the Sabine Pass LNG receiving terminal.


 
27

 

Overview of Significant 2009 Events
 
In 2009, we maintained commercial operability of the Sabine Pass LNG receiving terminal and continued to execute our strategy to complete construction of the Sabine Pass LNG receiving terminal and to generate steady and reliable revenues under Sabine Pass LNG’s long-term TUAs. The major events of 2009 include the following:

 
receipt of capacity reservation fee payments from Cheniere Marketing, Total and Chevron and successful unloading and processing of LNG for each customer;
 
 
purchase, transportation and successful unloading of an additional LNG commissioning cargo for the Sabine Pass LNG receiving terminal;
 
 
commencement of distributions to our subordinated unitholder; and
 
 
completed construction and achieved full operability of the Sabine Pass LNG receiving 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.
 
Liquidity and Capital Resources
 
Cash and Cash Equivalents
 
As of December 31, 2009, we had $117.5 million of cash and cash equivalents and $96.1 million of restricted cash and cash equivalents.  Of this amount, $117.4 million of cash and cash equivalents was held in our subsidiary, Sabine Pass LNG. The restricted cash and cash equivalents of $96.1 million was held by Sabine Pass LNG to pay interest on the Senior Notes.
 
The foregoing funds are anticipated to be sufficient to fund the remaining accrued liabilities related to construction, operating expenditures and interest requirements. Regardless whether Sabine Pass LNG receives revenues from Cheniere Marketing (or Cheniere, 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 Sabine Pass Indenture governing the Sabine Pass Notes before being able to make distributions to us, which will require that Cheniere Marketing make a substantial portion of its TUA payments to Sabine Pass LNG. As described below, Cheniere Marketing has a limited operating history, limited capital and no credit. If Sabine Pass LNG is unable to make restricted cash distributions to us, then we will likely be unable to make our anticipated future quarterly cash distributions on our units. Under such circumstances and absent additional external funding, Cheniere Marketing and Cheniere would likely be unable to meet their ongoing TUA and guarantee obligations to Sabine Pass LNG.
 
Construction
 
Construction at the Sabine Pass LNG receiving terminal was substantially completed in the third quarter of 2009. As of December 31, 2009, we had completed construction and attained full operability of the Sabine Pass LNG receiving 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), and such was accomplished within our budget.
 
TUA Revenues
 
The entire approximately 4.0 Bcf/d of regasification capacity at the Sabine Pass LNG receiving terminal has been fully reserved under two 20-year, firm commitment TUAs with unaffiliated third parties, and a third TUA with Cheniere Marketing. Each of the three customers at the Sabine Pass LNG receiving 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 the Sabine Pass LNG third-party customers as follows:
 
 
Total has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced on 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 has agreed to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced on July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.
 
    In addition, Cheniere Marketing has reserved the remaining 2.0 Bcf/d of regasification capacity and is entitled to use any capacity not utilized by Total and Chevron. Cheniere Marketing began making its TUA capacity reservation fee payments in the

 
 
28

 

fourth quarter of 2008.  Cheniere Marketing is required to make monthly capacity payments aggregating approximately $250 million per year for the period from January 1, 2009 through at least September 30, 2028.

Cheniere Marketing continues to develop its business, has a limited operating history, limited capital and lacks a credit rating.  Cheniere, which has guaranteed the obligations of Cheniere Marketing under its TUA, has a non-investment grade corporate rating.  In addition, the LNG and natural gas marketing business activities of Cheniere Marketing were downsized during 2008.  If Cheniere and its subsidiaries do not have sufficient liquidity to pay their obligations, including payments to us required under the Cheniere Marketing TUA, then Sabine Pass LNG will likely be unable to make restricted cash distributions to our partners under the Sabine Pass Indenture described below.  If Sabine Pass LNG is unable to make such restricted cash distributions, then we will likely be unable to make our anticipated future quarterly cash distributions on our units.  Under such circumstances and absent funding of a TUA reserve account, Cheniere Marketing and Cheniere would likely be unable to meet their TUA and guarantee obligations to Sabine Pass LNG.
 
Under each of these TUAs, Sabine Pass LNG is also entitled to retain 2% of the LNG delivered for the customer’s account, which Sabine Pass LNG will use primarily as fuel for revaporization and self-generated power at the Sabine Pass LNG receiving terminal.
 
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.
 

 
29

 

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, 2009, 2008 and 2007. 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,
 
 
2009
 
2008
 
2007
 
SOURCES OF CASH AND CASH EQUIVALENTS
                 
Use of restricted cash and cash equivalents
$
298,673
 
$
426,592
 
$
460,762
 
Operating cash flow
 
234,311
   
—  
   
 
Proceeds from issuance of debt
 
   
144,965   
   
 
Borrowings under long-term note—affiliate
 
114
   
1,708
   
645
 
Proceeds from issuance of common units
 
   
   
98,442
 
Affiliate payable
 
   
1
   
3
 
Total sources of cash and cash equivalents
 
533,098
   
573,266
   
559,852
 
USES OF CASH AND CASH EQUIVALENTS
                 
LNG receiving terminal construction-in-process
 
(96,918
)
 
(402,955
)
 
(430,405
)
Distributions to owners
 
(280,675
)
 
(45,824
)
 
(23,668
)
Advances under long-term contracts
 
(601
)
 
(14,274
)
 
(39,155
)
Repayment of long-term note—affiliate
 
(2,467
)
 
   
 
Advances to affiliate—LNG held for commissioning, net of amounts transferred to LNG receiving terminal construction-in-process
 
   
(9,923
)
 
 
Debt issuance costs
 
(23
)
 
(4,837
)
 
(725
)
Operating cash flow
 
   
(1,156
)
 
(640
)
Special rights adjustment
 
(34,879
)
 
   
 
Investments in restricted cash and cash equivalents
 
   
(94,303
)
 
 
Investment in restricted U.S. Treasury securities
 
   
   
(63,923
)
Other
 
   
   
(1,330
)
Total uses of cash and cash equivalents
 
(415,563
)
 
(573,272
)
 
(559,846
)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
 
117,535
   
(6
)
 
6
 
CASH AND CASH EQUIVALENTS—beginning of year
 
7
   
13
   
7
 
CASH AND CASH EQUIVALENTS—end of year
$
117,542
 
$
7
 
$
13
 
  
Use of restricted cash and cash equivalents
 
In 2009, 2008 and 2007, $298.7 million, $426.6 million and $460.8 million of restricted cash and cash equivalents, respectively, were primarily used to pay for scheduled interest payments and construction activities at the Sabine Pass LNG receiving terminal.  Under the Sabine Pass Indenture, a portion of the proceeds from the Senior Notes 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 receiving 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 are used, they are presented as a source of cash and cash equivalents.  The decreased use of restricted cash and cash equivalents in 2008 and 2009 primarily resulted from completing construction of the initial sendout capacity of approximately 2.6 Bcf/d and storage capacity of approximately 10.1 Bcf at the Sabine Pass LNG receiving terminal in September 2008, and the substantial completion of the Sabine Pass LNG receiving terminal’s construction activities during the third quarter 2009.
 
Operating cash flow
 
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.

 
30

 

Proceeds from issuance of debt
 
Proceeds from issuance of debt were $145.0 million in 2008. The $145.0 million 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 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 the quarter ended June 30, 2009.
 
LNG receiving terminal construction-in-process, net
 
Capital expenditures for the Sabine Pass LNG receiving terminal were $96.9 million, $403.0 million and $430.4 million in 2009, 2008 and 2007, respectively. Our capital expenditures decreased in 2009 as a result of the substantial completion of the construction of the Sabine Pass LNG receiving 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 receiving terminal.
 
Distributions to owners
 
We made $280.7 million of distributions to our common and subordinated unitholders and to our general partner in 2009.  We made $45.8 million and $23.7 million of distributions to common unitholders and to our general partner in 2008 and 2007, respectively.
 
Advances under long-term contracts
 
Sabine Pass LNG entered into certain contracts and purchase agreements related to the construction of the Sabine Pass LNG receiving 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 $0.6 million, $14.3 million and $39.2 million at December 31, 2009, 2008 and 2007, respectively. The decrease in 2009 compared to 2008 resulted from substantially completing construction of the Sabine Pass LNG receiving terminal in the third quarter of 2009. During 2009, the Sabine Pass LNG receiving terminal received equipment that it had previously advanced payment for under long-term contracts.  The decrease in 2008 compared to 2007 resulted from Sabine Pass LNG nearing completion of 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 receiving terminal. During 2008, the Sabine Pass LNG receiving 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 receiving terminal construction-in-process
 
During 2008, we advanced $9.9 million for LNG commissioning cargoes, net of amounts transferred to LNG receiving 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 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.  This contractual distribution has been presented as a Special rights adjustment to the equity accounts of Cheniere’s ownership on our Consolidated Statement of Partners’ Capital (Deficit) as of December 31, 2009.

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 receiving terminal, interest payments on the Senior Notes and establishment of a distribution reserve account pursuant to our partnership agreement.

 
31

 
 
Investment in restricted U.S. Treasury securities
 
Investment in restricted U.S. Treasury securities was $63.9 million in 2007.  Investments in restricted U.S. Treasury securities were contractually restricted to be used for a specific purpose.  We invested $63.9 million of the proceeds we received from our 2007 initial public offering to purchase U.S. Treasury securities that were contractually restricted to fund our distribution reserve account to be used for the payment of initial quarterly distributions through June 30, 2009.

Cash Distributions to Unitholders
 
We deposited all of the net proceeds that we received from our public offering into a distribution reserve in a separate account. The deposited amount was invested in U.S. Treasury securities maturing as to principal and interest at such times and in such amounts sufficient to pay the $0.425 initial quarterly distribution per common unit for all common units, as well as related distributions to our general partner, through the distribution made in respect of the quarter ended June 30, 2009. As provided under our partnership agreement, any amount remaining in the distribution reserve was to be distributed to Cheniere. We received sufficient cash from Sabine Pass LNG to make distributions to all of our unitholders for the quarter ended June 30, 2009 without withdrawing funds from the distribution reserve account. We therefore distributed $34.9 million to Cheniere from the distribution reserve account in August 2009 pursuant to the terms of our partnership agreement.
 
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, 2009:
 
           
Total Distribution (in thousands)
Date Paid
 
Period Covered by Distribution
 
Distribution Per Unit
 
Common and General Partner Units
 
Subordinated Units
February 13, 2009
 
October 1 – December 31, 2008 
 
$
0.425 
 
$
12,630 
 
$
57,538 
May 15, 2009
 
January 1 – March 31, 2009 
   
0.425 
 
$
12,630 
 
$
57,538 
August 14, 2009
 
April 1 – June 30, 2009 
   
0.425 
 
$
12,630 
 
$
57,538 
November 13, 2009
 
July 1, 2009 – September 30, 2009 
   
0.425 
 
$
12,630 
 
$
57,538 
 
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.  Based on our current projections, the earliest we anticipate that our subordination period may end would be no sooner than the first business day after the distribution is made in respect of the quarter ending March 31, 2012.
 
Debt Agreements
 
Senior Notes
 
Sabine Pass LNG has issued an aggregate principal amount of $2,215.5 million of Senior Notes consisting of $550.0 million of 7¼% Senior Secured Notes due 2013 and $1,665.5 million of 7½% Senior Secured Notes due 2016. 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, 2009, Sabine Pass LNG made distributions of $295.7 million to us after satisfying all the applicable conditions in the Sabine Pass Indenture.
 
Services Agreements
 
In February 2005, Sabine Pass LNG entered into a 20-year operation and maintenance 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. Prior to substantial completion of the Sabine Pass LNG receiving terminal, as defined in Sabine Pass LNG’s engineering, procurement and construction (“EPC”) contract with Bechtel Corporation (“Bechtel”), Sabine Pass LNG was required to pay a fixed monthly fee of $95,000 (indexed for inflation) under the agreement. The fixed monthly fee increased to $130,000 (indexed
  
 
32

 

for inflation) upon the achievement of substantial completion of the Sabine Pass LNG receiving terminal in March 2009, 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.
 
In February 2005, Sabine Pass LNG entered into a 20-year management services agreement with its general partner, which is a wholly-owned subsidiary of us, 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 operation and maintenance agreement described in the paragraph above. In August 2008, the general partner of Sabine Pass LNG assigned all of its rights and obligations under the management services agreement to Cheniere LNG Terminals, Inc. (“Cheniere Terminals”), a wholly-owned subsidiary of Cheniere. Prior to substantial completion of the Sabine Pass LNG receiving terminal, as defined in Sabine Pass LNG’s EPC contract with Bechtel, Sabine Pass LNG was required to pay Cheniere Terminals a monthly fixed fee of $340,000 (indexed for inflation). With the achievement of substantial completion of the Sabine Pass LNG receiving terminal in March 2009, the monthly fixed fee increased to $520,000 (indexed for inflation).
 
In March 2007, we entered into a services agreement with Cheniere Terminals pursuant to which we pay Cheniere Terminals an annual administrative fee of $10.0 million (adjusted for inflation) for the provision of various general and administrative services for our benefit following the closing of our initial public offering. Payments under this services agreement commenced January 1, 2009. In addition, we reimburse Cheniere Terminals for its services in an amount equal to the sum of all out-of-pocket costs and expenses incurred by Cheniere Terminals that are directly related to our business or activities.
 
During 2009, 2008 and 2007, we paid an aggregate of $18.5 million, $5.2 million and $5.2 million, respectively, under the foregoing service agreements.
 
State Tax Sharing Agreement
 
In November 2006, Sabine Pass LNG entered into a state tax sharing agreement with Cheniere effective for tax returns first due on or after January 1, 2008. Under this agreement, Cheniere has agreed to prepare and file all Texas franchise tax returns which it and Sabine Pass LNG are required to file on a combined basis and to timely pay the combined tax liability. If Cheniere, in its sole discretion, demands payment, Sabine Pass LNG will pay to Cheniere an amount equal to the Texas franchise tax that Sabine Pass LNG would be required to pay if its Texas franchise tax liability were computed on a separate company basis. This agreement contains similar provisions for other state and local taxes that Cheniere and Sabine Pass LNG are required to file on a combined, consolidated or unitary basis.
 
 
33

 

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, 2009 (in thousands).

 
Payments Due for Years Ended December 31,
 
 
Total
 
2010
 
2011-
2012
 
2013-
2014
 
Thereafter
 
Operating lease obligations (1) (2)
$
274,533   
 
$
8,905   
 
$
17,810   
 
$
17,810   
 
$
230,008   
 
Long-term debt (excluding interest) (3)
 
2,215,500   
     
   
   
550,000   
   
1,665,500   
  
Service contracts—
                             
Affiliate O&M agreement (4)
 
23,660   
   
1,560   
   
3,120   
   
3,120   
   
15,860   
   
Affiliate Sabine Pass LNG MSA (4)
 
94,640   
   
6,240   
   
12,480   
   
12,480   
   
63,440   
 
Affiliate services agreement (4)
 
192,500   
   
10,000   
    
20,000   
   
20,000   
   
142,500   
 
Construction and purchase obligations (4)
 
7,408   
     
7,408   
   
   
   
 
Cooperative endeavor agreements (4)
 
17,171   
    
2,453   
     
4,906   
    
4,906   
   
4,906   
 
Other Obligation (5)
 
3,01   
   
979   
   
2,039   
   
   
 
Total
$
2,828,430   
 
$
37,545   
  
$
60,355   
 
$
608,316   
 
$
2,122,214   
 
 

(1)
A discussion of these obligations can be found in Note 14—“Leases” of our Consolidated Combined Financial Statements.
 
(2)
Minimum lease payments have not been reduced by a minimum sublease rental of $129.6 million due in the future under noncancelable tug boat subleases.
 
(3)
Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2009, our cash payments for interest would be $164.8 million in 2010, $164.8 million in 2011, $164.8 million in 2012, $161.5 million in 2013, $124.9 million in 2014 and $239.3 million for the remaining years for a total of $1,020.1 million.  See Note 11—“Long-Term Debt (including related party”) of our Consolidated Combined Financial Statements.
 
(4)
A discussion of these obligations can be found in Note 13—“Related Party Transactions” to our Consolidated Combined Financial Statements.
 
(5)
Other obligation consists of LNG receiving terminal security services.
 
Results of Operations
 
Overall Operations
 
2009 vs. 2008
 
Our consolidated net income increased $265.2 million, from a $78.3 million net loss in 2008 to a $186.9 million net income in 2009. This $265.2 million increase in net income in 2009 resulted from the commencement of revenues under the Cheniere Marketing TUA beginning October 1, 2008, the Total TUA on April 1, 2009 and the Chevron TUA on July 1, 2009.

2008 vs. 2007
 
Our consolidated net loss increased $29.3 million, from a $49.0 million net loss in 2007 to a $78.3 million net loss in 2008. The $29.3 million increase in net loss in 2008 was primarily due to decreased interest income, increased depreciation expense, increased operating and maintenance expense and increased operating and maintenance expense-affiliate, which were partially offset by decreased interest expense and derivative gain.
 
LNG TUA Revenue
 
2009 vs. 2008
 
Our LNG TUA revenue 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.

 
34

 

LNG TUA Revenue from Affiliate
 
2009 vs. 2008
 
Our LNG TUA revenue from 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 receiving terminal in September 2008, Cheniere Marketing made a capacity payment of $15.0 million for October, November and December of 2008.

2008 vs. 2007
 
Our LNG TUA revenue from affiliate increased from zero in 2007 to $15.0 million in 2008. Following the achievement of commercial operability of the Sabine Pass LNG receiving terminal in September 2008, Cheniere Marketing made a capacity payment of $15.0 million for October, November and December of 2008. We did not have TUA revenue in 2007, as the Sabine Pass LNG receiving terminal was not yet completed.

Operating and Maintenance Expense (including Affiliate Expense)
 
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 receiving terminal in the third quarter of 2008 and the substantial completion of construction and achievement of full operability of the Sabine Pass LNG receiving 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.

2008 vs. 2007

Operating and maintenance expense (including affiliate expense) increased $11.5 million, from zero in 2007 to $11.5 million in 2008. This $11.5 million increase resulted from the achievement of commercial operability of the initial 2.6 Bcf/d of regassification capacity and the 10.1 Bcf of storage capacity in September 2008 and also included costs to repair damage caused by Hurricane Ike.
 
Depreciation Expense
 
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 receiving 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 receiving 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.

2008 vs. 2007

Depreciation expense increased $8.0 million, from zero in 2007 to $8.0 million in 2008. This $8.0 million increase resulted from our having begun depreciating the Sabine Pass LNG receiving terminal’s initial 2.6 Bcf/d of regassification capacity and 10.1 Bcf of storage capacity commencing in the third quarter of 2008 when it achieved commercial operability.

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 the Sabine Pass LNG receiving terminal in March 2009 and due to the commencement of the services agreement with Cheniere Terminals on January 1, 2009.

 
35

 

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.

2008 vs. 2007
 
Interest income decreased $38.4 million, from $52.2 million in 2007 to $13.8 million in 2008. This decrease resulted from less restricted cash and cash equivalents invested and lower interest rates during 2008 compared to 2007.
 
Interest Expense, net
 
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 receiving terminal into service in September 2008 and achievement of full operability of the Sabine Pass LNG receiving 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.

2008 vs. 2007
 
Interest expense, net of amounts capitalized, decreased $8.8 million, from $88.7 million in 2007 to $79.9 million in 2008. This decrease in interest expense, net of amount capitalized, primarily resulted from an increase in construction costs and consequently an increase in capitalized interest in 2008 compared to 2007.
 
Derivative Gain
 
2008 vs. 2007
 
Derivative gain increased $4.7 million, from zero in 2007 to $4.7 million in 2008.  On behalf of Sabine Pass LNG, Cheniere Marketing entered into natural gas swaps to hedge the exposure to variability in expected future cash flows from sales of excess LNG purchased for commissioning and performance testing during 2008.
  
Off-Balance Sheet Arrangements
 
As of December 31, 2009, 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 combined 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.
 
 
36

 
 
We capitalized interest and other related debt costs during the construction period of the Sabine Pass LNG receiving 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 receiving terminal is recognized as revenues 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, U.S. 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 combined 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 combined 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 April 2009, the Financial Accounting Standards Board (“FASB”) issued a staff position providing additional guidance on factors to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The guidance was effective for interim and annual periods ending after June 15, 2009. The implementation of this standard did not have a material impact on our financial position, results of operations or cash flow.
 
In April 2009, the FASB issued a staff position requiring fair value disclosures in both interim as well as annual financial statements in order to provide more timely information about the effects of current market conditions on financial instruments. The guidance is effective for interim and annual periods ending after June 15, 2009. The implementation of this standard did not have a material impact on our financial position, results of operations or cash flow.
 
In May 2009, the FASB issued new requirements for reporting subsequent events. These requirements set forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and disclosures that an entity should make about events or transactions that occurred after the balance sheet date. Disclosure of the date through which an entity has evaluated subsequent events and the basis for the date is also required. This disclosure should alert all users of financial statements that an entity has not evaluated subsequent events after the date set forth in the financial statements being presented. The Company started adhering to these requirements in the second quarter of 2009.
 
 
37

 
 
In June 2009, the FASB issued SFAS No. 168, FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. SFAS No. 168 establishes the FASB Accounting Standards Codification (the “Codification”) as the single source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. SFAS No. 168 and the Codification are effective for financial statements issued for interim and annual periods ending after September 15, 2009. As of July 1, 2009, the Codification supersedes all existing non-SEC accounting and reporting standards. We adopted this statement for the period ended September 30, 2009. The adoption of this statement did not have an impact on our financial position, results of operations or cash flow.
 
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 sheet.
 
Marketing and Trading Commodity Price Risk
 
On behalf of Sabine Pass LNG, Cheniere Marketing has entered into exchange cleared NYMEX natural gas swaps entered into to hedge the exposure to variability in expected future cash flows related to commissioning cargoes purchased by Cheniere Marketing that were or are expected to be sold as part of the testing phase of the commissioning process and operations.  We use value at risk (“VaR”) and other methodologies for market risk measurement and control purposes.  The VaR is calculated using the Monte Carlo simulation method. At December 31, 2009 and 2008, the one-day VaR with a 95% confidence interval on our derivative positions was less than $0.1 million.

As of December 31, 2009, Cheniere Marketing, on behalf of Sabine Pass LNG, had entered into a total of 360,851 MMBtu of NYMEX natural gas swaps through February 2010, for which we will receive fixed prices of $4.903 to $6.158 per MMBtu.  At December 31, 2009, the value of the derivatives was an asset of $0.1 million.
 
 
38

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
INDEX TO FINANCIAL STATEMENTS
 
CHENIERE ENERGY PARTNERS, L.P.
 
40 
41 
43 
44 
45 
46 
47 
62 
 

 
39

 

MANAGEMENT’S REPORT TO THE UNITHOLDERS OF CHENIERE ENERGY PARTNERS, L.P.
 
Management’s Report on Internal Control Over Financial Reporting
 
As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Cheniere Energy Partners, L.P. (“Cheniere Partners”) and its subsidiaries. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Cheniere Partners’ system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.
 
Based on our assessment, we have concluded that Cheniere Partners maintained effective internal control over financial reporting as of December 31, 2009, 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
 
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.
 
                                                                   
 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)
 

 
40

 

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, 2009 and 2008, and the related consolidated combined statements of operations, partners’ and owners’ capital (deficit), and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cheniere Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2010 expressed an unqualified opinion thereon.
 
 
 
/s/    ERNST & YOUNG LLP
ERNST & YOUNG LLP
 
 
 
Houston, Texas
February 25, 2010
 
41

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors of Cheniere Energy Partners, GP, LLC, and
Unitholders of Cheniere Energy Partners, L.P.
 
We have audited Cheniere Energy Partners, L. P. and subsidiaries’ internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Cheniere Energy Partners, L.P. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, Cheniere Energy Partners, L.P. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cheniere Energy Partners, L.P. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated combined statements of operations, partners’ and owners’ capital (deficit), and cash flows for each of the three years in the period ended December 31, 2009 and our reported dated February 25, 2010 expressed an unqualified opinion thereon.
 
 
 
/s/    ERNST & YOUNG LLP
ERNST & YOUNG LLP
 
 
 
 
                                          
Houston, Texas
February 25, 2010

 
42

 

CHENIERE ENERGY PARTNERS, L.P. AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
 
   
December 31,
 
   
2009
   
2008
 
ASSETS
           
CURRENT ASSETS
           
Cash and cash equivalents
 
$
117,542
   
$
7
 
Restricted cash and cash equivalents
   
13,732
     
235,985
 
Accounts and interest receivable
   
5,037
     
2,087
 
Accounts receivable—affiliate
   
3,586
     
419
 
Advances to affiliate
   
5,358
     
2,198
 
Advances to affiliate—LNG inventory
   
1,319
     
—  
 
LNG inventory
   
1,521
     
—  
 
Prepaid expenses and other
   
4,836
     
5,407
 
Total current assets
   
152,931
     
246,103
 
                 
NON-CURRENT RESTRICTED CASH AND CASH EQUIVALENTS
   
82,394
     
137,984
 
NON-CURRENT RESTRICTED U.S. TREASURY SECURITIES
   
—  
     
20,829
 
PROPERTY, PLANT AND EQUIPMENT, NET
   
1,588,557
     
1,517,507
 
DEBT ISSUANCE COSTS, NET
   
26,953
     
30,748
 
ADVANCES UNDER LONG-TERM CONTRACTS
   
1,021
     
10,705
 
ADVANCES TO AFFILIATE—LNG HELD FOR COMMISSIONING
   
—  
     
9,923
 
OTHER
   
7,617
     
5,036
 
Total assets
 
$
1,859,473
   
$
1,978,835
 
                 
LIABILITIES AND PARTNERS’ DEFICIT
               
CURRENT LIABILITIES
               
Accounts payable
 
$
39
   
$
137
 
Accounts payable—affiliate
   
306
     
514
 
Accrued liabilities
   
22,181
     
40,926
 
Accrued liabilities—affiliate
   
3,095
     
184
 
Deferred revenue
   
26,456
     
2,500
 
Deferred revenue—affiliate
   
63,507
     
62,742
 
Total current liabilities
   
115,584
     
107,003
 
                 
LONG-TERM DEBT, NET OF DISCOUNT
   
2,110,101
     
2,107,673
 
LONG-TERM DEBT—RELATED PARTY, NET OF DISCOUNT
   
72,928
     
70,661
 
LONG-TERM DEBT—AFFILIATE
   
—  
     
2,372
 
DEFERRED REVENUE
   
33,500
     
37,500
 
DEFERRED REVENUE—AFFILIATE
   
7,360
     
4,971
 
OTHER NON-CURRENT LIABILITIES
   
327
     
340
 
                 
COMMITMENTS AND CONTINGENCIES
   
—  
     
—  
 
                 
PARTNERS’ DEFICIT
               
Common unitholders (26,416,357 units issued and outstanding at December 31, 2009 and 2008)
   
(41,494
)
   
(23,520
)
Subordinated unitholders (135,383,831 units issued and outstanding at December 31, 2009 and 2008)
   
(427,026
)
   
(318,994
)
General partner interest (2% interest with 3,302,045 units issued and outstanding at December 31, 2009 and 2008)
   
(11,807
)
   
(9,171
)
Total partners’ deficit
   
(480,327
)
   
(351,685
)
Total liabilities and partners’ deficit
 
$
1,859,473
   
$
1,978,835
 
 

See accompanying notes to consolidated combined financial statements.

 
43

 

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

   
Year Ended December 31,
 
   
2009
   
2008
   
2007
 
REVENUES
                 
Revenues
  $ 163,862     $ —       $ —     
Revenues—affiliate
    252,928       15,000       —    
TOTAL REVENUE
    416,790       15,000       —    
                         
EXPENSES
                       
Operating and maintenance expense
    20,683       6,345       —    
Operating and maintenance expense—affiliate
    11,833       5,125       —    
Depreciation expense
    32,742       7,994       35  
Development expense
    —         1,184       1,542  
Development expense—affiliate
    —         1,158       3,943  
General and administrative expense
    3,722       4,843       2,716  
General and administrative expense—affiliate
    19,890       5,492       4,280  
TOTAL EXPENSES
    88,870       32,141       12,516  
INCOME (LOSS) FROM OPERATIONS
    327,920       (17,141 )     (12,516 )
                         
OTHER INCOME (EXPENSE)
                       
Interest income
    930       13,778       52,225  
Interest expense, net
    (147,201 )     (79,887 )     (88,661 )
Interest expense—affiliate
    (13 )     —         —    
Derivative gain, net
    5,277       4,653       —    
Other
    (1 )     253       —    
TOTAL OTHER EXPENSE
    (141,008 )     (61,203 )     (36,436 )
NET INCOME (LOSS)
  $ 186,912     $ (78,344 )   $ (48,952 )
                         
Less:
                       
Net loss through March 25, 2007
                    (12,128 )
                         
Net loss for partners from March 26, 2007 through December 31, 2007
                  $ (36,824 )
                         
Allocation of net income (loss):
                       
Limited partners’ interest
    183,174       (76,777 )     (36,088 )
General partner’s interest
    3,738       (1,567 )     (736 )
Net income (loss) for partners
  $ 186,912     $ (78,344 )   $ (36,824 )