S-1 1 ds1.htm FORM S-1 Form S-1
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on December 21, 2006

Registration No. 333-            

 

 


UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


Form S-1

REGISTRATION STATEMENT

UNDER THE SECURITIES ACT OF 1933

 


CHENIERE ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 


 

Delaware   2813   20-5913059

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

717 Texas Avenue, Suite 3100

Houston, Texas 77002

(713) 659-1361

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Don A. Turkleson

Chief Financial Officer

717 Texas Avenue, Suite 3100

Houston, Texas 77002

(713) 659-1361

(Name, address, including zip code, and telephone number including area code, of agent for service)

 


Copies to:

 

Geoffrey K. Walker

Andrews Kurth LLP

600 Travis, Suite 4200

Houston, Texas 77002

(713) 220-4200

 

Joshua Davidson

Sean T. Wheeler

Baker Botts L.L.P.

One Shell Plaza

910 Louisiana Street

Houston, Texas 77002

(713) 229-1234

 


Approximate date of commencement of proposed sale to the public:    As soon as practicable after this Registration Statement becomes effective.

 


If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

CALCULATION OF REGISTRATION FEE

 


Title of Each Class of

Securities to be Registered

   Proposed Maximum
Aggregate Offering
Price(1)(2)
   Amount of
Registration Fee

Common Units representing limited partner interests

   $ 301,875,000    $ 32,301

(1)   Includes common units issuable upon exercise of the underwriters’ over-allotment option.
(2)   Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 



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Index to Financial Statements

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED DECEMBER 21, 2006

P R O S P E C T U S

LOGO

12,500,000 Common Units

Representing Limited Partner Interests

Cheniere Energy Partners, L.P.

$          per unit

 


We are a limited partnership recently formed by Cheniere Energy, Inc., or Cheniere. This is the initial public offering of our common units. This prospectus relates to 5,210,331 common units to be offered by us and 7,289,669 common units to be offered by Cheniere LNG Holdings, LLC, an affiliate of Cheniere. We expect the initial public offering price to be between $             and $             per unit. The selling unitholder has granted the underwriters a 30-day option to purchase up to an additional 1,875,000 common units to cover over-allotments. We will not receive any proceeds from any common units sold by the selling unitholder. We intend to apply for listing of our common units on the                      Exchange under the symbol “        .”

We will establish a distribution reserve with the net proceeds that we receive from this offering, which will be used to fund the payment of the initial quarterly distribution of $0.425 per unit on all common units and general partner units through the quarter ending June 30, 2009.

Investing in our common units involves risks. Please read “ Risk Factors” beginning on page 19.

These risks include the following:

 

    We are a development stage company without any revenues, operating cash flows or operating history. If our efforts to complete construction of the Sabine Pass LNG receiving terminal are unsuccessful or substantially delayed for any reason, you may lose all or a portion of your investment.

 

    We are dependent on three customers for all of our revenue. If any of these customers fails to perform under its terminal use agreement, or TUA, for any reason, our business will be materially and adversely affected and you may lose all or a portion of your investment.

 

    Until we begin to receive significant cash flows under our TUAs, which we expect to occur in 2009, our distributions to you will come from the distribution reserve and will be a return of your investment.

 

    Half of our contracted TUA revenue is from an affiliate of our general partner, Cheniere Marketing, which has a limited operating history, limited capital, no credit rating and an untested business strategy.

 

    If Cheniere Marketing is unable to enter into commercial arrangements for the use of its contracted capacity at the Sabine Pass LNG receiving terminal or otherwise generate funds, it will be unable to make its TUA payments without financial support from Cheniere, which has guaranteed Cheniere Marketing’s obligations under its TUA. Cheniere has a non-investment grade corporate rating of B.

 

    Cheniere Marketing’s ability to satisfy its obligations under its TUA is dependent on favorable industry conditions, including increased demand for LNG in the United States.

 

    The indenture governing the Sabine Pass LNG notes issued to fund construction of the Sabine Pass LNG receiving terminal prohibits cash distributions to us unless specified conditions have been satisfied, including a fixed charge coverage ratio test. Because payments under the other two customers’ TUAs will not provide sufficient coverage after March 31, 2009, substantial additional revenues from the Cheniere Marketing TUA or from other sources will be required to satisfy the indenture test. If these additional payments are not received from the Cheniere Marketing TUA or from other sources, or if Cheniere Marketing makes the payments but those payments are not considered revenue under generally accepted accounting principles, the indenture will prevent Sabine Pass LNG from making distributions to us. As a result, we would be unable to make any distributions on our common units.

 

    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 and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.

 

    Holders of our common units are not entitled to elect our general partner or its directors.

 

    You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

 


 

     Per
Common Unit
   Total

Initial public offering price

   $                     $             

Underwriting discount(1)

   $      $  

Proceeds to Cheniere Energy Partners, L.P.

   $      $  

Proceeds to selling unitholder (before expenses)

   $      $  

(1)   Includes a structuring fee equal to 0.50% of the gross proceeds of this offering, or approximately $     million, payable to the joint book-running managers.

The underwriters expect to deliver the common units on or about                     , 2007.

 


Joint Book-Runners

 

Citigroup   Merrill Lynch & Co.   Credit Suisse

                    , 2007


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[GRAPHIC TO COME]

 


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Index to Financial Statements

You should rely only on the information contained in this prospectus. We have not, and the underwriters and selling unitholder have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters and selling unitholder are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

 


TABLE OF CONTENTS

 

     Page

Presentation of Information

   iv

Cautionary Statement Regarding Forward-Looking Statements

   iv

Summary

   1

Cheniere Energy Partners, L.P. 

   1

Formation Transactions and Partnership Structure

   8

The Offering

   11

Forecast of Cash Available to Pay Distributions

   15

Selected Financial Data of Our Combined Predecessor Entities

   18

Risk Factors

   19

Risks Relating to Our Business in General

   19

Risks Relating to Completion of the Sabine Pass LNG Receiving Terminal

   20

Risks Relating to Our Cash Distributions

   24

Risks Relating to Development and Operation of Our Business

   28

Risks Relating to an Investment in Us and Our Common Units

   36

Risks Relating to Tax Matters

   42

Use of Proceeds

   45

Capitalization

   46

Dilution

   47

Cash Distribution Policy and Restrictions on Distributions

   48

General

   48

Cash Distributions

   50
     Page

How We Make Cash Distributions

   60

Operating Surplus and Capital Surplus

   60

Distribution Reserve

   63

Subordination Period

   63

Distributions of Available Cash from Operating Surplus During the Subordination Period

   64

Distributions of Available Cash from Operating Surplus After the Subordination Period

   64

Incentive Distribution Rights

   65

Percentage Allocations of Available Cash from Operating Surplus

   65

Distributions from Capital Surplus

   66

Adjustment to the Initial Quarterly Distribution and Target Distribution Levels

   66

Distributions of Cash Upon Liquidation

   67

Selected Financial Data of Our Combined Predecessor Entities

   70

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   71

Overview

   71

Our Contracted Capacity

   71

Liquidity and Capital Resources

   72

Results of Operations

   78

Other Matters

   79

New Accounting Pronouncements

   79

Quantitative and Qualitative Disclosures About Market Risk

   81

 

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Index to Financial Statements
     Page

Industry

   82

Overview

   82

LNG Supply Chain

   83

Worldwide Natural Gas Reserves

   83

LNG Exporters

   84

LNG Importers

   85

North American Regasification Facilities

   85

Business

   87

Overview

   87

Business Strategies

   87

Competitive Strengths

   87

Our Relationship with Cheniere

   89

LNG Receiving Terminal Development

   90

Customers

   92

FERC and Other Governmental Regulation

   97

Environmental Regulation

   99

Competition

   100

Insurance

   100

Employees

   102

Legal Proceedings

   102

Description of Principal Construction Agreements

   103

Phase 1 EPC Agreement

   103

Phase 2 – Stage 1 EPCM Agreement

   106

Phase 2 – Stage 1 EPC LNG Tank Contract

   108

Phase 2 – Stage 1 EPC LNG Soil Contract

   112

Indebtedness

   116

Indenture

   116

Collateral Trust Agreement

   121

Security Agreement and Mortgage

   121

Pledge Agreement

   122

Security Deposit Agreement

   122

Management

   123

Management of Cheniere Energy Partners, L.P. 

   123
     Page

Directors and Executive Officers of Our General Partner

   124

Executive Compensation

   126

Long-Term Incentive Plan

   126

Reimbursement of Expenses

   127

Security Ownership of Certain Beneficial Owners and Management and the Selling Unitholder

   128

Certain Relationships and Related Transactions

   129

Distributions and Payments to Our General Partner and Its Affiliates

   129

Agreements Governing the Transactions

   130

Contribution Agreement

   130

Our Services Agreement

   130

Sabine Pass LNG Operation and Maintenance Agreement

   131

Sabine Pass LNG Management Services Agreement

   131

Sabine Pass LNG General Partner Management Services Agreement

   132

Cheniere Marketing TUA

   132

J&S Cheniere Agreement

   132

Assumption Agreement

   132

Arrangement Regarding Taxes

   133

Conflicts of Interest and Fiduciary Duties

   134

Conflicts of Interest

   134

Fiduciary Duties

   138

Description of the Common Units

   141

The Common Units

   141

Transfer Agent and Registrar

   141

Transfer of Common Units

   141

The Partnership Agreement

   143

Organization and Duration

   143

Purpose

   143

Power of Attorney

   143

Capital Contributions

   143

Voting Rights

   143

Limited Liability

   145

Issuance of Additional Securities

   146

Amendment of Our Partnership Agreement

   146

 

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Index to Financial Statements
     Page

Merger, Sale or Other Disposition of Assets

   148

Termination and Dissolution

   149

Liquidation and Distribution of Proceeds

   149

Withdrawal or Removal of Our General Partner

   150

Transfer of General Partner Interest

   151

Transfer of Ownership Interests in Our General Partner

   151

Transfer of Incentive Distribution Rights

   151

Change of Management Provisions

   152

Limited Call Right

   152

Non-Eligible Citizen; Redemption

   152

Non-Taxpaying Assignees; Redemption

   153

Meetings; Voting

   153

Status as Limited Partner or Assignee

   154

Indemnification

   154

Reimbursement of Expenses

   154

Books and Reports

   154

Right to Inspect Our Books and Records

   155

Registration Rights

   155

Units Eligible for Future Sale

   156
     Page

Material Tax Consequences

   157

Partnership Status

   157

Limited Partner Status

   159

Tax Consequences of Unit Ownership

   159

Tax Treatment of Operations

   164

Disposition of Common Units

   165

Uniformity of Units

   167

Tax-Exempt Organizations and Other Investors

   167

Administrative Matters

   168

State, Local and Other Tax Considerations

   170

Investment in Cheniere Energy Partners, L.P. by Employee Benefit Plans

   172

Underwriting

   173

Validity of the Common Units

   176

Experts

   176

Independent Engineer

   176

Where You Can Find More Information

   176

Index to Financial Statements

   F-1

Appendix A—Form of First Amended and Restated Agreement of Limited Partnership of Cheniere Energy Partners, L.P

   A-1

Appendix B—Independent Engineer’s Report

   B-1

 

References in this prospectus to “Cheniere Energy Partners, L.P.,” “we,” “our,” “us” or like terms when used in a historical context refer to the business conducted by Sabine Pass LNG, L.P. and its general partner and limited partner, the equity interests of which are being contributed to Cheniere Energy Partners, L.P. in connection with this offering. When used in the present tense or prospectively, those terms refer to Cheniere Energy Partners, L.P. and its subsidiaries. References to “Cheniere” with respect to periods prior to the closing of this offering mean Cheniere Energy, Inc., together with its subsidiaries, as the historical owner and operator of our business, while those references with respect to periods from and after the closing of this offering, mean Cheniere Energy, Inc., together with its subsidiaries, as the indirect owner of our general partner. References to “Sabine Pass LNG” refer to Sabine Pass LNG, L.P., our indirect wholly-owned subsidiary. References to the “selling unitholder” and “Cheniere Holdings” refer to Cheniere LNG Holdings, LLC, an indirect subsidiary of Cheniere and our sole limited partner prior to the closing of this offering.

 

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Index to Financial Statements

PRESENTATION OF INFORMATION

In this prospectus, unless the context otherwise requires:

 

    Bcf means billion cubic feet;

 

    Bcf/d means billion cubic feet per day;

 

    cm means cubic meter;

 

    EPC means engineering, procurement and construction;

 

    EPCM means engineering, procurement, construction and management;

 

    FERC means the Federal Energy Regulatory Commission;

 

    LNG means liquefied natural gas;

 

    Mcf means thousand cubic feet;

 

    MMcf/d means million cubic feet per day;

 

    MMbtu means million British thermal units;

 

    Tcf means trillion cubic feet; and

 

    TUA means terminal use agreement.

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements, which are statements other than statements of historical fact. Forward-looking statements include, among others:

 

    statements regarding our ability to pay distributions to our unitholders;

 

    statements relating to the construction and operation of the Sabine Pass LNG receiving terminal, including statements concerning the completion or expansion thereof by certain dates or at all, the costs related thereto and certain characteristics, including amounts of regasification and storage capacity, the number of storage tanks and docks, pipeline deliverability and the number of pipeline interconnections, if any;

 

    statements relating to the construction and operation of facilities related to the Sabine Pass LNG receiving terminal;

 

    statements regarding our expected receipt of cash distributions from Sabine Pass LNG;

 

    statements regarding our ability to make any acquisitions in the future or, if made, our ability to integrate them into our existing business and to operate them in a profitable manner;

 

    statements regarding future levels of domestic natural gas production, supply or consumption; future levels of liquefied natural gas, or 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 or hydrocarbon products;

 

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

 

   

statements regarding any terminal use agreement, or TUA, or other agreement to be entered into or performed substantially in the future, including any cash distributions and revenues anticipated to be

 

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Index to Financial Statements
 

received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification 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 any independent engineer’s or other expert’s assumptions, estimates, projections or conclusions;

 

    statements regarding conflicts of interest with Cheniere and its affiliates;

 

    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 such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy” and similar terms. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they 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 prospectus.

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. Other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

 

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Index to Financial Statements

SUMMARY

This summary highlights information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the historical financial statements and the notes to those financial statements. You should read “Risk Factors” for information about important risks to consider before buying the common units. Unless otherwise indicated, the information presented in this prospectus assumes an initial offering price per common unit of $         and that the underwriters’ option to purchase additional units is not exercised.

Cheniere Energy Partners, L.P.

Overview

We are a Delaware limited partnership recently formed by Cheniere Energy, Inc., or Cheniere. Through our wholly-owned subsidiary, Sabine Pass LNG, we will develop, own and operate the Sabine Pass LNG receiving terminal currently under construction in western Cameron Parish, Louisiana on the Sabine Pass Channel.

Construction of the Sabine Pass LNG receiving terminal began in March 2005. Upon completion of construction, the Sabine Pass LNG receiving terminal will be the largest LNG receiving terminal in North America with approximately 4.0 Bcf/d of regasification capacity and approximately 16.8 Bcf of LNG storage capacity. All of this capacity has been contracted for under three 20-year, firm commitment terminal use agreements, or TUAs. Each customer must make payments on a “take-or-pay” basis, which means that the customer will be obligated to pay the full contracted amount of monthly fees whether or not it uses any of its reserved capacity. Provided the Sabine Pass LNG receiving terminal has achieved the required level of commercial operation, which we expect will occur in the third quarter of 2008, these “take-or-pay” TUA payments will be made as follows:

 

    Total LNG USA, Inc., or Total, has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly payments to us aggregating approximately $125 million per year for 20 years commencing April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion. Total, S.A. has Moody’s and Standard & Poor’s corporate ratings of Aa1 and AA, respectively.

 

    Chevron U.S.A., Inc., or Chevron, has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly payments to us aggregating approximately $125 million per year for 20 years commencing not later than July 1, 2009. Chevron Corporation has guaranteed up to 80% of the fees payable by Chevron under its TUA. Chevron Corporation has Moody’s and Standard & Poor’s corporate ratings of Aa2 and AA, respectively.

 

    Cheniere Marketing, Inc., or Cheniere Marketing, a wholly-owned subsidiary of Cheniere, has reserved approximately 2.0 Bcf/d of regasification capacity, is entitled to use any capacity not utilized by Total and Chevron and has agreed to make monthly payments to us aggregating approximately $250 million per year for at least 19 years commencing January 1, 2009. In addition, Cheniere Marketing has agreed to make payments of $5 million per month during an initial commercial operations ramp-up period in 2008. Cheniere has guaranteed Cheniere Marketing’s obligations under its TUA. Cheniere has no Moody’s rating and a Standard & Poor’s corporate rating of B.

The Sabine Pass LNG Receiving Terminal

The initial phase, or Phase 1, of the Sabine Pass LNG receiving terminal was designed and permitted with a regasification capacity of 2.6 Bcf/d, three LNG storage tanks with an aggregate LNG storage capacity of 10.1 Bcf and two unloading docks capable of handling the largest LNG carriers currently being operated or built. In July 2006, Sabine Pass LNG received approval from the Federal Energy Regulatory Commission, or the FERC, to increase the regasification capacity of the Sabine Pass LNG receiving terminal from 2.6 Bcf/d to 4.0 Bcf/d by adding up to three additional LNG storage tanks, additional vaporizers and related facilities. We refer to the

 

1


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Index to Financial Statements

entire FERC- approved expansion as Phase 2. The first stage of the Phase 2 expansion will include two additional LNG storage tanks, additional vaporizers and related facilities, and will achieve a full operability at approximately 4.0 Bcf/d and an aggregate storage capacity of approximately 16.8 Bcf. We refer to this expansion as Phase 2 – Stage 1. We will conduct further Phase 2 expansion, if any, including construction of a potential sixth LNG storage tank, in one or more subsequent stages.

The timeline below sets forth the anticipated timing for completing construction of Phase 1 and Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal and the timing of payments to Sabine Pass LNG under the TUAs.

LOGO

We estimate that the cost to construct Phase 1 of the Sabine Pass LNG receiving terminal will be approximately $900 million to $950 million, before financing costs. We estimate that the cost to construct Phase 2 – Stage 1 will be approximately $500 million to $550 million, before financing costs. These cost estimates are subject to change due to such items as cost overruns, change orders, delays in construction, increased component and material costs, escalation of labor costs and increased spending to maintain the construction schedule. As of October 31, 2006, Sabine Pass LNG had paid $531.1 million and $46.3 million of Phase 1 and Phase 2 – Stage 1 construction costs, respectively. In order to finance the remaining construction expenditures, Sabine Pass funded a construction account in November 2006 with $886.7 million of the proceeds from the issuance of $2,032 million of its senior secured notes, which we refer to as the Sabine Pass LNG notes. Please read “Indebtedness” for more information about the Sabine Pass LNG notes and, among other things, the restricted payment requirements imposed on Sabine Pass LNG by the indenture governing the Sabine Pass LNG notes.

Business Strategies

Our primary business objectives are to complete construction of the Sabine Pass LNG receiving terminal and, thereafter, 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:

 

    manage the development and construction of the Sabine Pass LNG receiving terminal to achieve completion, commissioning and commercial operation in a timely manner and on budget;

 

    after construction and commissioning, operate the Sabine Pass LNG receiving terminal safely, at a low cost and in an efficient manner, utilizing proven, conventional regasification technology; and

 

    expand our existing asset base through acquisitions from Cheniere or third parties of complementary businesses or assets, such as pipelines, other LNG receiving terminals and natural gas storage assets.

 

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Index to Financial Statements

Competitive Strengths

We believe that we have several strengths in pursuing our business strategies.

Contracted and Stable Long-Term Cash Flows.    All of the regasification capacity that will be available at the Sabine Pass LNG receiving terminal upon completion of Phase 1 and Phase 2 – Stage 1 is reserved under long-term TUAs. The TUAs are structured to provide Sabine Pass LNG with stable cash flows as a result of the following:

 

    $250 Million of Revenues Annually from Total and Chevron.    Total and Chevron have each agreed to pay Sabine Pass LNG on a “take-or-pay” basis a monthly fixed capacity reservation fee plus a monthly operating fee in a fixed amount that is adjusted annually for inflation. The Total and Chevron TUAs are supported by guarantees from Total, S.A. and Chevron Corporation, respectively, which have Moody’s and Standard & Poor’s corporate ratings of Aa1/AA and Aa2/AA, respectively. Contracted cash revenues of approximately $250 million per year under the Total and Chevron TUAs, which are expected to begin in the third quarter of 2009, should be sufficient by themselves to cover:

 

    all annual debt service on the Sabine Pass LNG notes, which will be approximately $151 million; and

 

    all other annual costs of operating Sabine Pass LNG, which will be approximately $48 million for the four consecutive quarters ending June 30, 2010.

 

     The remaining funds from Total and Chevron will be sufficient for us to pay the operating expenses of our partnership and the initial quarterly distribution on all of our common units and general partner units so long as those funds are distributable to us under the indenture governing the Sabine Pass LNG notes.

 

    No Direct LNG Supply Risk or Direct Commodity Price Risk under the TUAs.    The customers, rather than Sabine Pass LNG, bear all direct risks associated with obtaining supplies of LNG, transporting LNG to the Sabine Pass LNG receiving terminal, arranging for pipelines to transport regasified LNG from the receiving terminal to natural gas markets, and assuring that the regasified LNG satisfies downstream natural gas pipeline quality specifications. Under the TUAs, the amount of the cash payments Sabine Pass LNG is entitled to receive from its customers will not be affected by changes in demand for, or the price of, LNG or natural gas. Marketing and direct commodity price risks are borne by Sabine Pass LNG’s customers.

 

    Long-term Commitments.    Under the TUAs, Sabine Pass LNG’s customers have committed to make monthly payments for 20-year terms. Sabine Pass LNG’s customers have options to extend their TUAs for one or more additional 10-year terms. Sabine Pass LNG’s customers are able to terminate their TUAs before 20 years only in limited circumstances, such as a force majeure delay that extends for 18 months or more, and are required to continue to make monthly payments for up to 18 months even if terminal services are unavailable due to a force majeure event.

Please read “Risk Factors” for information regarding Sabine Pass LNG’s dependence upon contractual revenues under the Cheniere Marketing TUA and the risk that Sabine Pass LNG may not be able to distribute any cash to us, including cash received from Total and Chevron, in the event that it does not receive the contracted revenues under the Cheniere Marketing TUA.

Solid Construction Arrangements.    Bechtel Corporation, or Bechtel, is our EPC contractor under a lump-sum turnkey EPC agreement for Phase 1 and is providing design and engineering services and acting as construction manager for Phase 2 – Stage 1. Our construction agreements with Bechtel provide bonuses for early completion, and the EPC agreement for Phase 1 obligates Bechtel to pay liquidated damages for delayed completion. We believe these provisions mitigate the potential for delays. In addition, Sabine Pass LNG has fixed the costs for a substantial majority of the materials used to construct the Sabine Pass LNG receiving terminal, which minimizes the risk posed by escalation of these prices.

 

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Index to Financial Statements

Early Mover Advantage.    Cheniere established its LNG business plan in 1999 at a time when the construction of new LNG import capacity in North America was being seriously considered for the first time since completion of the last domestic LNG import terminal in the early 1980s. As a result, Cheniere secured what we believe is one of the best available North American sites for the Sabine Pass LNG receiving terminal. Located at the Texas/Louisiana border only 3.7 miles from open waters near the Gulf of Mexico, the Sabine Pass LNG receiving terminal site is easily accessible by the largest LNG transport vessels currently operating or being built. The Sabine Pass LNG receiving terminal is located in close proximity to interconnection points with numerous existing natural gas pipelines.

Ample Pipeline Access.    We anticipate that the Sabine Pass LNG receiving terminal will have ample access to natural gas markets. Kinder Morgan Energy Partners, L.P. has announced that it is building a 3.2 Bcf/d take-away pipeline system from the Sabine Pass LNG receiving terminal to interconnection points that will transport natural gas to the interstate pipeline network. Total and Chevron have both announced agreements with Kinder Morgan securing 100% of the initial capacity on this pipeline for 20 years. In addition, Cheniere Sabine Pass Pipeline, L.P., a subsidiary of Cheniere, is developing a 16-mile natural gas pipeline from the Sabine Pass LNG receiving terminal that is designed to transport 2.6 Bcf/d to interconnection points with existing natural gas transmission pipelines. Cheniere Marketing has contracted to use this pipeline, and construction is expected to commence in the second quarter of 2007.

Economies of Scale.    With approximately 4.0 Bcf/d of sendout capacity and approximately 16.8 Bcf of storage capacity upon completion of Phase 2 – Stage 1, the Sabine Pass LNG receiving terminal will be the largest LNG receiving terminal in North America, designed to have more than two times the capacity of any other terminal operating in North America. With this capacity, we believe that the Sabine Pass LNG receiving terminal will benefit from economies of scale in operating expenses. After completing Phase 1, we expect that the annual operating expenses of the Sabine Pass LNG receiving terminal will be approximately $35 million to support 2.6 Bcf/d of sendout capacity. We expect annual operating expenses will only increase by approximately $2 million to support the full 4.0 Bcf/d of sendout capacity upon completion of Phase 2 – Stage 1.

Environmentally and Community Friendly Approach.    We are committed to an environmentally sound and community friendly approach in developing and operating the Sabine Pass LNG receiving terminal. We consider investing time and effort into developing strong community relationships a key factor in ensuring the success of the Sabine Pass LNG receiving terminal. Sabine Pass LNG began the application process for the Sabine Pass LNG receiving terminal only after it was convinced that the local community understood the process and was willing to support the Sabine Pass LNG receiving terminal project.

Experienced Management Team.    Cheniere has assembled a team of professionals with extensive experience in the LNG industry to pursue its business, including construction and operation of the Sabine Pass LNG receiving terminal. Through tenure with major oil companies, operators of LNG receiving terminals, pipelines, and engineering and construction companies, Cheniere’s senior management team has substantial experience in the areas of LNG project development, operation, engineering, technology, transportation and marketing. Because of our relationship with Cheniere, we will continue to have access to these professionals not only for the operation of the Sabine Pass LNG receiving terminal but also for any future growth opportunities.

Our Relationship with Cheniere

Cheniere is the indirect owner of our general partner, as well as of our common and subordinated units that will represent a 90.4% limited partner interest in us upon completion of this offering. Cheniere is engaged primarily in the business of developing onshore LNG receiving terminals, and related natural gas pipelines, along the Gulf Coast of the United States. Cheniere is also developing a business to market LNG and natural gas, primarily through Cheniere Marketing. To a limited extent, Cheniere is also engaged in oil and natural gas exploration and development activities in the Gulf of Mexico.

 

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Index to Financial Statements

Cheniere Marketing has entered into a TUA for all of the regasification capacity at the Sabine Pass LNG receiving terminal not reserved and utilized by Total and Chevron. As a result, approximately 50% of our anticipated combined revenues will be attributable to fees paid by Cheniere Marketing under its TUA with Sabine Pass LNG, which will be guaranteed by Cheniere. Cheniere Marketing is a small, development stage company, with a limited operating history, limited capital, no credit rating and an untested business strategy. Cheniere Marketing’s business plan is to purchase LNG on a short-term and long-term basis, to regasify the LNG at Sabine Pass LNG or other LNG receiving terminals, and to trade natural gas and market its regasified LNG in North America and other worldwide natural gas markets. It intends to earn a profit on the purchase of LNG and sale of natural gas after paying its TUA and pipeline fees and other operating expenses. Cheniere Marketing has no agreements or arrangements for supplies of LNG, a limited history of trading natural gas and no unconditional commitments from customers for the purchase of natural gas.

In addition to the Sabine Pass LNG receiving terminal, Cheniere has two other LNG receiving terminals that are currently in early stages of development: the Corpus Christi LNG receiving terminal near Corpus Christi, Texas, and the Creole Trail LNG receiving terminal at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. If constructed in accordance with the permits that have been issued by the FERC, these two terminals would have an aggregate designed regasification capacity of approximately 5.9 Bcf/d. Cheniere is also developing, and anticipates constructing, natural gas pipelines to connect each of the three LNG receiving terminals to North American natural gas markets.

In the future, we may have opportunities to acquire some or all of these assets from Cheniere at an appropriate stage of commercialization and development, although we cannot predict whether any acquisitions will be made available to us or whether we will pursue or complete any future acquisitions. Our relationship with Cheniere also provides us with access to Cheniere’s management talent, market insights and significant industry relationships. Although we believe that our relationship with Cheniere is a strength, it is also a source of conflicts of interest. 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. Please read “Conflicts of Interest and Fiduciary Duties.”

Independent Engineer’s Report

This prospectus contains a report by Stone & Webster Management Consultants, Inc., or the Independent Engineer. The Independent Engineer is a leading consulting and engineering firm that devotes a substantial portion of its resources to providing services related to the technical, environmental and economic aspects of industrial facilities. The Independent Engineer’s report analyzes certain construction, technical, environmental and economic aspects of the Sabine Pass LNG receiving terminal. This report includes, among other things, discussions of the technology used at the Sabine Pass LNG receiving terminal, engineering and construction execution issues and costs, operating plans, timing matters, environmental permitting status, and a technical review of the construction and related documents pertaining to the Sabine Pass LNG receiving terminal. A copy of the report is attached as Appendix B to this prospectus and should be read in its entirety.

In the preparation of its report, the Independent Engineer has relied on assumptions regarding circumstances beyond the control of us or any other person. By their nature, these assumptions are subject to significant uncertainties, and actual results will differ, perhaps materially, from those stated in the report. We cannot give any assurance that these assumptions will prove to be correct. If our actual results are materially less favorable than those shown in the Independent Engineer’s report, or if the assumptions prove to be incorrect, Sabine Pass LNG’s ability to pay distributions to us, and our ability to pay distributions to our unitholders, may be adversely affected.

 

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Index to Financial Statements

Summary of Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. Those risks are described under the caption “Risk Factors” and include:

Risks Relating to Our Business in General

 

    We are a development stage company without any revenues, operating cash flows, operating history or experience constructing, operating or maintaining an LNG facility, and if we are unable to complete construction of the Sabine Pass LNG receiving terminal or if our customers fail to perform under their contracts for whatever reason, our business will be materially and adversely affected and you could lose all or a significant portion of your investment.

 

    Until we begin to receive cash flows under all three of our TUAs in 2009, all or a portion of our distributions to you will be a return of your investment.

 

    Our substantial indebtedness could adversely affect our ability to operate our business and to pay or increase distributions to you.

Risks Relating to Completion of the Sabine Pass LNG Receiving Terminal

 

    Sabine Pass LNG’s inability to timely construct and commission the Sabine Pass LNG receiving terminal would prevent it from commencing operations when anticipated and would delay or prevent it, and consequently us, from realizing anticipated cash flows. Factors that might delay or prevent completion of construction include failure of the contractors to fulfill their contractual obligations, failure to enter additional agreements with contractors, shortages of materials, difficulty in financing any cost overruns, difficulties in obtaining LNG for commissioning activities, failure to obtain necessary governmental and third-party permits, weather conditions and other catastrophes, labor shortages or disputes, and local community resistance.

 

    We are dependent on Bechtel and other contractors for the successful completion of the Sabine Pass LNG receiving terminal.

 

    We may experience cost overruns.

Risks Relating to Our Cash Distributions

 

    We may not have sufficient cash from operations to enable us to fund the initial quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner and funding of capital expenditures.

 

    Sabine Pass LNG may be restricted under the terms of the indenture governing the Sabine Pass LNG notes from making distributions to us and from incurring additional indebtedness under certain circumstances, which may limit our ability to pay or increase distributions to you.

 

    Cost reimbursements and management fees due to our general partner and its affiliates will reduce cash available to pay distributions to you.

 

    Our financial estimates, including our forecast of cash available for distribution, and our Independent Engineer’s conclusions are based on certain assumptions that may not materialize.

Risks Relating to Development and Operation of Our Business

 

    We will be dependent for substantially all of our revenues and cash flows on the TUA counterparties, including Cheniere Marketing, which has a limited operating history, limited capital, no credit rating and an untested business strategy.

 

    After the Sabine Pass LNG receiving terminal is placed in service, its business will involve significant operational risks.

 

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    Sabine Pass LNG may be required to purchase more natural gas than anticipated 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.

 

    The inability to import LNG into the U.S. could materially adversely affect our customers, particularly Cheniere Marketing, and our business plans and results of operations if Sabine Pass LNG has to replace TUAs that terminate or expire.

 

    Failure of sufficient LNG liquefaction capacity to be constructed worldwide could adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions.

 

    A shortage of LNG tankers worldwide could adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions.

 

    Failure of imported LNG to become a competitive source of energy in North America could adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions.

 

    Decreases in the price of natural gas could lead to reduced development of LNG projects worldwide, which could adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions.

 

    Cyclical changes in the demand for LNG regasification capacity may adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions.

 

    We may face competition from competitors with far greater resources, as well as potential overcapacity in the LNG receiving terminal marketplace.

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 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 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.

 

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

 

    Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

 

    You will experience immediate and substantial dilution of $18.66 per common unit.

 

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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 entity level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation or if we were to become subject to a material amount of entity level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.

 

    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.

 

    You may be required to pay taxes on your share of our taxable income even if you do not receive any cash distributions from us.

 

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

Formation Transactions and Partnership Structure

General

We are a Delaware limited partnership formed in November 2006. At the closing of this offering, the following transactions will occur:

 

    Cheniere LNG Holdings, LLC, which we refer to as Cheniere Holdings, will contribute through us to our wholly-owned subsidiary, Cheniere Energy Investments, LLC, all of its equity interests in Sabine Pass LNG-GP, Inc. and Sabine Pass LNG-LP, LLC, which own all of the equity interests in Sabine Pass LNG;

 

    we will issue to Cheniere Holdings 21,206,026 common units and 135,383,831 subordinated units;

 

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

 

    we will issue 5,210,331 common units to the public in this offering;

 

    we will use our net proceeds from this offering to establish a $96.7 million distribution reserve as described in “—The Offering;”

 

    Cheniere Holdings will sell 7,289,669 common units to the public in this offering, after which Cheniere Holdings and the public will have an aggregate 90.4% and 7.6% limited partner interest in us, respectively;

 

    our general partner will enter into a services agreement with an affiliate of Cheniere for the provision of various general and administrative services for an annual administrative fee of $10 million, adjusted for inflation after January 1, 2007, beginning in the first quarter of 2009; and

 

    our general partner will enter into a services and secondment agreement pursuant to which we anticipate that certain employees of a Cheniere affiliate will be seconded to our general partner to provide operating and routine maintenance services with respect to the Sabine Pass LNG receiving terminal.

As is common with publicly traded limited partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries.

 

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Organizational Structure

The following table and diagram depict our ownership and organizational structure, after giving effect to this offering and the related transactions, and our relationship with Cheniere and Cheniere Marketing.

 

Public Common Units

   7.6 %

Cheniere and Affiliate Common Units

   8.4 %

Cheniere and Affiliate Subordinated Units

   82.0 %

General Partner Units

   2.0 %
      

Total

   100.0 %
      

LOGO

 

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Index to Financial Statements

Management of Our Partnership

Our general partner, Cheniere Energy Partners GP, LLC, will manage our operations and activities. Cheniere indirectly owns and controls our general partner. An affiliate of Cheniere will receive an annual administrative fee of $10 million, adjusted for inflation after January 1, 2007, beginning in the first quarter of 2009 for the provision of various general and administrative services to us and will also be entitled to reimbursement of all direct expenses incurred on our behalf. Our general partner will also be entitled to distributions on its general partner units and, if specified requirements are met, on its incentive distribution rights. Please read “Cash Distribution Policy and Restrictions on Distributions” and “Certain Relationships and Related Transactions.” Unlike stockholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or its directors.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 717 Texas Avenue, Suite 3100, Houston, Texas 77002, and our telephone number is (713) 659-1361. Our website is http://www.                    .com. We will make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties

Our general partner has a fiduciary duty to manage us in a manner beneficial to our unitholders. However, because our general partner is indirectly wholly-owned by Cheniere, the officers and directors of our general partner also have fiduciary duties to manage the business of our general partner in a manner beneficial to Cheniere. Certain of the executive officers and non-independent directors of our general partner also serve as executive officers and directors of Cheniere. As a result of these relationships, conflicts of interest exist and may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. Cheniere and its affiliates may compete directly with us and do not have an obligation to present business opportunities to us. For more detailed descriptions of the conflicts of interest of our general partner, please read “Risk Factors—Risks Relating to an Investment in Us and Our Common Units” and “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest.”

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to our unitholders. By purchasing a common unit, you are treated as having consented to various actions contemplated in the partnership agreement and to conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to our unitholders.

For a description of our other relationships with our affiliates, especially Cheniere Marketing, please read “Certain Relationships and Related Transactions.”

 

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The Offering

 

Common units offered by us

5,210,331 common units.

 

Common units offered by the selling unitholder

7,289,669 common units, or 9,164,669 common units if the underwriters exercise their option to purchase additional units in full.

 

Units outstanding after this offering

26,416,357 common units, representing a 16% limited partner interest, 135,383,831 subordinated units, representing an 82% limited partner interest, and 3,302,045 general partner units, representing a 2% general partner interest.

 

Use of proceeds

We estimate that we will receive net proceeds of approximately $96.7 million from the sale of our common units in this offering, after deducting the underwriting discount and structuring fee on each unit sold, assuming an initial public offering price of $20.00 per common unit. All of our net proceeds will be used to fund a distribution reserve to pay the $0.425 initial quarterly distribution on all common units and general partner units through the distribution made in respect of the quarter ending June 30, 2009.

 

 

The selling unitholder will pay the same underwriting discount and structuring fee on each unit sold, as well as all other costs related to this offering. The selling unitholder has granted the underwriters an option to purchase additional common units to cover over-allotments, if any, in connection with this offering. We will not receive any proceeds from any common units sold by the selling unitholder, including proceeds received from any exercise of the underwriters’ option to purchase additional common units.

 

Distribution reserve

We will set aside $96.7 million as a distribution reserve in a separate account to pay the $0.425 initial quarterly distribution per common unit for all common units and general partner units through the distribution made in respect of the quarter ending June 30, 2009. The distribution reserve will be restricted cash on our balance sheet and will be invested in money market securities or U.S. treasuries. In the event that we issue additional common units prior to June 30, 2009, we will use a portion of the net proceeds from such issuance to increase the distribution reserve by an amount that our general partner, with the concurrence of the conflicts committee of its board of directors, determines is required to fund the initial quarterly distribution for such additional common units and related general partner units from their date of issuance through the distribution made in respect of the quarter ending June 30, 2009. Any amount remaining in the distribution reserve on August 15, 2009 will be distributed to Cheniere Holdings. We may distribute amounts in the distribution reserve to Cheniere Holdings prior to August 15, 2009 if our general partner, with the concurrence of the conflicts committee, determines that such reserves are not necessary to provide for distributions on all of our common units and general partner units for any quarter ending on or prior to June 30, 2009.

 

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Anticipated cash distributions

We must distribute all of our cash on hand at the end of each quarter, less any reserves established by our general partner. We refer to this as available cash, and we define its meaning in our partnership agreement. We expect that we will not have sufficient operating cash flow under the TUAs to pay the full initial quarterly distribution on all the common and general partner units until the third quarter of 2009. Therefore, we will use the distribution reserve to fund the initial quarterly distribution on the common units and general partner units through the quarter ending June 30, 2009.

 

 

For each calendar quarter, we intend to pay the initial quarterly distribution on all of our outstanding units to the extent that we have sufficient cash in the distribution reserve and from operations, after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay the initial quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.” In general, we will pay any cash distributions that we make with respect to each such quarter in the following manner:

 

    first, 98% to the common units and 2% to our general partner, until each common unit has received the initial quarterly distribution of $0.425 plus any arrearages from prior quarters;

 

    second, 98% to the subordinated units and 2% to our general partner, until each subordinated unit has received the initial quarterly distribution of $0.425; and

 

    thereafter, 98% to all units, pro rata, and 2% to our general partner, until each unit has received an aggregate distribution equal to $0.489.

 

 

If cash distributions per unit are greater than $0.489 in any such quarter, our general partner will receive increasing percentages, up to 50%, of the cash that we distribute in excess of that amount. We refer to these distributions as incentive distributions.

 

 

Cash distributions on the common units will generally be made within 45 days after the end of each quarter. The initial quarterly distribution for the period from the closing of this offering through the end of the quarter in which the closing occurs will be adjusted based on the actual length of the period.

 

Subordination period

During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the initial quarterly distribution plus any arrearages on the initial quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

 

 

The subordination period generally will end if:

 

   

we have earned and paid at least $0.425 on each outstanding common unit, subordinated unit and general partner unit for any

 

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three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2010; or

 

    if we have earned and paid at least $0.638 (150% of the initial quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for any four consecutive quarters ending on or after March 31, 2008.

 

 

The subordination period will also end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal. Please read “How We Make Cash Distributions—Subordination Period.”

 

 

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, the common units will no longer be entitled to any arrearages and the converted units will then participate pro rata with the other common units in distributions of available cash.

 

Issuance of additional units

During the subordination period, we may not issue any additional common units or units senior to our common units without the approval of the conflicts committee of the board of directors of our general partner. For any additional common units that we issue prior to June 30, 2009, we must increase the distribution reserve by an amount that our general partner, with the concurrence of the conflicts committee of its board of directors, determines is required to fund the initial quarterly distribution on such additional common units and related general partner units from their date of issuance through the distribution in respect of the quarter ending June 30, 2009. After the subordination period, we can issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the conflicts committee. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Securities.”

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or the directors of our general partner. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of 92.3% of our common and subordinated units (approximately 91.2% if the underwriters exercise their option to purchase additional common units in full). This will give our general partner the practical ability to prevent its involuntary removal. Please read “The Partnership Agreement—Voting Rights.”

 

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Limited call right

If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner has the right, but not the obligation, to purchase all, but not less than all, of our remaining common units at a price not less than the current market price, as defined in our partnership agreement, of our common units. Please read “The Partnership Agreement—Limited Call Right.”

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than         % of the cash distributed to you with respect to that period. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

 

Material tax consequences

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

 

Exchange listing

We intend to apply for listing of our common units on the                  Exchange under the symbol “            .”

 

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Forecast of Cash Available to Pay Distributions

The following table summarizes our forecast of the expected revenues, EBITDA and cash available to pay the initial quarterly distribution of $0.425 on all of our outstanding common units, subordinated units and general partner units for each of the four quarters in the twelve-month period ending June 30, 2010. Prior to June 30, 2009, we will use funds from the distribution reserve to pay the initial quarterly distribution of $0.425 on all of our outstanding common units and general partner units. This information should be read in conjunction with the more detailed information presented in the table illustrating our forecast of cash available for distribution for the period from March 31, 2007 through June 30, 2010, including the accompanying footnotes, explanations and descriptions of assumptions relating thereto, set forth under “Cash Distribution Policy and Restrictions on Distributions.”

The information set forth below summarizes our anticipated results of operations, including the projected revenues under our 20-year TUAs with Total, Chevron and Cheniere Marketing, for the first four consecutive quarters in which we expect to receive operating revenues under all three TUAs. In preparing this information, we have relied on assumptions regarding circumstances beyond the control of us or any other person. By their nature, the assumptions are subject to significant uncertainties, and actual results will differ, perhaps materially, from those forecasted. We cannot give any assurance that these assumptions are correct or that this information will reflect actual results. Accordingly, this forecast is not intended to be a prediction of future results. If our actual results are materially less favorable than those shown, or if the assumptions used in preparing this information prove to be incorrect, our ability to make distributions to our unitholders may be adversely affected. For additional information relating to our financial forecast, please read “Risk Factors—Risks Relating to Our Cash Distributions—Our financial estimates, including our forecast of cash available for distribution, and our Independent Engineer’s conclusions are based on certain assumptions that may not materialize.” For information about risks relating to Cheniere Marketing’s business as a development stage company, please read “Risk Factors—Risks Relating to Development and Operation of Our Business—We will be dependent for substantially all of our revenues and cash flows on the TUA counterparties, including Cheniere Marketing, which has a limited operating history, limited capital, no credit rating and an untested business strategy.”

 

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Forecast of Cash Available for Distribution

Four Quarters Ending June 30, 2010

(in millions)

 

TUA revenues(1)

  

Total TUA(2)

   $ 125.5  

Chevron TUA(2)

     129.9  

Cheniere Marketing TUA

     255.7  
        

Aggregate TUA revenues

     511.1  

Deferred revenues(2)

     (4.0 )

Operating expenses of Sabine Pass LNG(3)

     (36.7 )

Assumed commissioning costs(4)

     —    

State and local taxes

     (9.9 )
        

Sabine Pass LNG EBITDA(5)

     460.5  

Maintenance capital expenditures(3)

     (1.5 )

Interest on Sabine Pass LNG Notes(6)

     (151.0 )

General and administrative expenses of our partnership(7)

     (13.3 )
        

Cash available for distribution

     294.7  
        

Annual distributions to:

  

Publicly held common units

     (21.3 )

Common units held by affiliates of our general partner

     (23.7 )

Subordinated units held by affiliates of our general partner

     (230.1 )

General partner units held by our general partner

     (5.6 )
        

Total annual distributions

     (280.7 )
        

Surplus

   $ 14.0  
        

(1)   Fixed capacity reservation fees, including an operating fee component subject to adjustment for annual consumer price index inflation (assumed to be 2.5% annually).
(2)   TUA revenues include $2 million of annual non-cash deferred revenues during the first ten years under each of the Total and Chevron TUAs related to $20 million of advance capacity reservation fees previously received from each of Total and Chevron.
(3)   Combined Sabine Pass LNG operating expenses and maintenance capital expenditures are as estimated by us and the Independent Engineer. See the report of the Independent Engineer, attached as Appendix B to this prospectus. Maintenance capital expenditures estimated by us at $1.5 million per year beginning in 2009, escalating with inflation at 2.5% annually thereafter, are presented separately in this table.
(4)   We anticipate that these commissioning costs will be paid before the third quarter of 2009.
(5)   Calculated as Sabine Pass LNG’s aggregate TUA revenues less non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes. See “—Non-GAAP Financial Measure” below for more information.
(6)   Assumes total debt consists solely of the $2,032 million of the Sabine Pass LNG notes, which have a weighted-average fixed interest rate of 7.432% paid semi-annually.
(7)   Estimated tax compliance and publicly traded partnership tax reporting, accounting, SEC reporting and other costs of operating as a publicly traded partnership of $2.5 million per year and, beginning in the first quarter of 2009, annual payments of $10 million per year to a Cheniere affiliate for providing general and administrative services to us, in each case as adjusted for assumed inflation at 2.5% per year after January 1, 2007.

 

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Non-GAAP Financial Measure

Sabine Pass LNG’s EBITDA is computed as total revenues less non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes. It does not include depreciation expenses and certain non-operating items. Because we have not forecasted such depreciation expense and non-operating items, we have not made any forecast of net income, which would be the most directly comparable financial measure under generally accepted accounting principles, or GAAP. As a result, we are unable to reconcile differences between forecasts of EBITDA and net income. EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as commercial banks, to assess:

 

    the anticipated financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

 

    the ability of our assets to generate cash sufficient to pay interest on our indebtedness; and

 

    our anticipated operating performance and return on invested capital compared to other comparable companies, without regard to their financing methods and capital structure.

Sabine Pass LNG’s EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Sabine Pass LNG’s EBITDA excludes some, but not all, items that affect net income and operating income, and these measures may vary among companies. Therefore, Sabine Pass LNG’s EBITDA may not be comparable to similarly titled measures of other companies.

 

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Selected Financial Data of Our Combined Predecessor Entities

The following tables set forth the selected financial data of our predecessor entities on a combined basis for the periods and at the dates indicated. Our combined predecessor entities refers to Sabine Pass LNG and its limited partner and general partner.

The combined statement of operations data for the period from October 20, 2003 (inception) through December 31, 2003, for the years ended December 31, 2004 and 2005, and the combined balance sheet information at December 31, 2004 and 2005 are derived from our audited combined financial statements, which are included elsewhere in this prospectus. The summary combined balance sheet information at December 31, 2003 has been derived from our audited combined balance sheet as of December 31, 2003, which is not included in this prospectus. We have derived the combined statement of operations data for the nine months ended September 30, 2005 and 2006 and for the period from October 20, 2003 (inception) to September 30, 2006, and the combined balance sheet data at September 30, 2006 from our unaudited combined financial statements, which are included elsewhere in this prospectus. The unaudited combined financial statements have been prepared on the same basis as the audited combined financial statements and, in the opinion of management of our general partner, include all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation of the information set forth therein. Our past financial or operating performance is not a reliable indicator of our future performance (particularly anticipated revenues, debt costs and expenses), and you should not use our historical performance to anticipate results or future period trends.

We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the combined financial statements and the accompanying notes included in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

    Combined Predecessor Entities  
   

Period from

October 20,

2003

(inception) to

December 31,

2003

   

Year ended

December 31,

   

Nine months ended

September 30,

   

Period from

October 20,

2003

(inception) to

September 30,

2006

 
      2004     2005     2005     2006    
    (in thousands)  
                      (unaudited)     (unaudited)     (unaudited)  

Statement of Operations Data:

           

Revenues

  $ —       $ —       $ —       $ —       $ —       $ —    

Expenses

    2,763       4,682       4,718       3,410       9,399       21,563  
                                               

Loss from operations

    (2,763 )     (4,682 )     (4,718 )     (3,410 )     (9,399 )     (21,563 )

Other income

    —         28       456       83       112       597  
                                               

Net loss

  $ (2,763 )   $ (4,654 )   $ (4,262 )   $ (3,327 )   $ (9,287 )   $ (20,966 )
                                               

Cash Flow Data:

           

Cash flows provided by (used in) operating activities

  $ 101     $ 23,192     $ 6,320     $ 3,204     $ (6,231 )   $ 23,382  

Cash flows used in investing activities

    (101 )     (124 )     (246,337 )     (180,998 )     (296,383 )     542,944  

Cash flows provided by (used in) financing activities

    —         (1,246 )     218,200       156,002       302,621       519,575  

 

     Combined Predecessor Entities
     December 31,    September 30,
2006
     2003    2004    2005   
     (in thousands)
                    (unaudited)

Balance Sheet Data:

           

Cash and cash equivalents (unrestricted)(1)

   $ —      $ 21,822    $ 5    $ 7

Property, plant and equipment

     96      212      270,740      563,988

Total assets

     101      23,316      309,139      613,832

Long-term debt(1)

     —        —        72,485      386,730

Deferred revenues

     —        22,000      40,000      40,000

Total other long-term liabilities

     2,864      17,418      120      19,927

(1)   In November 2006, Sabine Pass LNG issued $2,032 million of senior secured notes due 2013 and 2016 and repaid all outstanding debt incurred under an amended and restated credit facility; $886.7 million of the net proceeds received from the issuance of the Sabine Pass LNG notes was deposited in a restricted construction account.

 

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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. You should carefully consider the following risk factors together with all of the other information included in this prospectus when evaluating an investment in our common units. If any of the following risks were to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

The risk factors in this section are grouped into the following categories:

 

    Risks Relating to Our Business in General, beginning on this page 19;

 

    Risks Relating to Completion of the Sabine Pass LNG Receiving Terminal, beginning on page 20;

 

    Risks Relating to Our Cash Distributions, beginning on page 24;

 

    Risks Relating to Development and Operation of Our Business, beginning on page 28;

 

    Risks Relating to an Investment in Us and Our Common Units, beginning on page 36; and

 

    Risks Relating to Tax Matters, beginning on page 42.

Risks Relating to Our Business in General

We are a development stage company without any revenues, operating cash flows, operating history or experience constructing, operating or maintaining an LNG facility, and if we are unable to complete construction of the Sabine Pass LNG receiving terminal or if our customers fail to perform under their contracts for whatever reason, our business will be materially and adversely affected and you could lose all or a significant portion of your investment.

We are a newly-formed development stage company with no revenues, operating cash flows or operating history. We have had net losses of $9.3 million and $21.0 million for the nine months ended September 30, 2006 and the period from inception through September 30, 2006, respectively. We expect to continue to incur losses and experience negative operating cash flow through 2008 and to incur significant capital expenditures through completion of development of the Sabine Pass LNG receiving terminal. Any delays beyond the expected development periods for the Sabine Pass LNG receiving terminal would prolong, and could increase the level of, our operating losses and negative operating cash flows. Neither we nor Cheniere and its affiliates have ever managed the construction, operation or maintenance of an LNG facility.

As more fully discussed in subsequent risk factors, our ability to generate sufficient cash flow to pay the initial quarterly distribution on all units is dependent on the successful and timely completion of the Sabine Pass LNG receiving terminal and on the ability of our three customers, Chevron, Total and Cheniere Marketing, to perform their obligations under their TUAs. Cheniere Marketing has a limited operating history, and Cheniere has a non-investment grade corporate rating. As a result, Cheniere Marketing and Cheniere have a higher risk of being financially unable to perform on the Cheniere Marketing TUA than either Chevron or Total under their TUAs.

Until we begin to receive cash flows under all three of our TUAs in 2009, all or a portion of our distributions to you will be a return of your investment.

Except to the extent that we receive revenues under TUAs, all distributions on our common units will be made from the distribution reserve through the distribution in respect of the second quarter of 2009 and will be a return of your investment. We do not expect to receive any TUA revenues until 2008, and we do not expect to receive sufficient revenues under our TUAs to cover all distributions to you until the third quarter of 2009.

 

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Our substantial indebtedness could adversely affect our ability to operate our business and to pay or increase distributions to you.

As of November 30, 2006, we had approximately $2,032 million of indebtedness, consisting entirely of the Sabine Pass LNG notes. Our substantial indebtedness could have important consequences, including:

 

    limiting our ability to pay distributions to our unitholders;

 

    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;

 

    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 compete with other companies who are not as highly leveraged;

 

    limiting our ability to react to changing market conditions in our industry and in our customers’ industries and to economic downturns;

 

    limiting our flexibility in planning for, or reacting to, changes in our business and future business opportunities;

 

    making us more vulnerable than a less leveraged company to a downturn in our business or in the economy;

 

    limiting our ability to attract customers; and

 

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

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 indenture governing the Sabine Pass LNG notes from making distributions to us and from incurring additional indebtedness under certain circumstances, which may limit our ability to pay or increase distributions to you.”

Our ability to satisfy our obligations will depend upon our future operating performance. Prevailing economic conditions and financial, business and other factors, many of which are beyond our control, will affect our ability to make payments on our debt obligations. We do not expect to receive full contracted revenues under the Cheniere Marketing TUA until the first quarter of 2009 and under the Total and Chevron TUAs until the second and third quarters of 2009, respectively. If we cannot thereafter generate sufficient cash from operations to meet our other obligations, we may need to refinance all or a portion of our indebtedness, including the Sabine Pass LNG notes, on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.

Risks Relating to Completion of the Sabine Pass LNG Receiving Terminal

Sabine Pass LNG’s inability to timely construct and commission the Sabine Pass LNG receiving terminal would prevent it from commencing operations when anticipated and would delay or prevent it, and consequently us, from realizing anticipated cash flows.

Sabine Pass LNG may not complete Phase 1 or Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal in a timely manner, or at all, due to numerous factors, some of which are beyond our control. Factors that could adversely affect our planned completion include:

 

    failure by Bechtel or the other contractors to fulfill their obligations under their construction contracts or disagreements with them over their contractual obligations;

 

    failure by Sabine Pass LNG to enter into satisfactory additional agreements with contractors for the rest of Phase 2 – Stage 1;

 

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    shortages of materials or delays in delivery of materials;

 

    cost overruns and difficulty in obtaining sufficient debt or equity financing to pay for such additional costs;

 

    difficulties or delays in obtaining LNG for commissioning activities necessary to achieve commercial operability of the Sabine Pass LNG receiving terminal;

 

    failure to obtain all necessary governmental and third-party permits, licenses and approvals for the construction and operation of the Sabine Pass LNG receiving terminal;

 

    weather conditions, such as hurricanes, and other catastrophes, such as explosions, fires, floods and accidents;

 

    difficulties in attracting a sufficient skilled and unskilled workforce, increases in the level of labor costs and the existence of any labor disputes;

 

    resistance in the local community to the development of the Sabine Pass LNG receiving terminal due to safety, environmental or security concerns; and

 

    local and general economic and infrastructure conditions.

Sabine Pass LNG’s inability to timely complete the Sabine Pass LNG receiving terminal, including as a result of any of the foregoing factors, could prevent it from commencing operations when anticipated, which could delay payments under the TUAs. As a result, we may not receive our anticipated cash flows on time or at all.

We are dependent on Bechtel and other contractors for the successful completion of the Sabine Pass LNG receiving terminal.

We have no experience constructing LNG receiving terminals and limited experience working with EPC contractors, including Bechtel, and with other construction contractors. Timely and cost-effective completion of the Sabine Pass LNG receiving terminal in compliance with agreed specifications is central to our business strategy and is highly dependent on our contractors’ performance under their agreements with Sabine Pass LNG. Our contractors’ ability to perform successfully under their contracts is dependent on a number of factors, including their ability to:

 

    design and engineer the Sabine Pass LNG receiving terminal to operate in accordance with specifications;

 

    engage and retain third-party subcontractors and procure equipment and supplies;

 

    respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;

 

    attract, develop and retain skilled personnel, including engineers;

 

    post required construction bonds and comply with the terms thereof;

 

    manage the construction process generally, including coordinating with other contractors and regulatory agencies; and

 

    maintain their own financial condition, including adequate working capital.

These risks are heightened for Phase 2 – Stage 1, which is still in the contracting phase. A substantial number of contracts, such as for performing portions of or supplying materials for Phase 2 – Stage 1, remain to be negotiated for Phase 2 – Stage 1, and we may be unable to reach satisfactory arrangements for these contracts. As a result, the scope, design, timing and cost for Phase 2 – Stage 1 construction are not as well defined as they are for Phase 1, and therefore the risk of delays, cost overruns or non-completion is greater for Phase 2 – Stage 1 than for Phase 1.

 

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Although some of our EPC contracts provide for liquidated damages, if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Sabine Pass LNG receiving terminal, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as result of any such delay or impairment. In addition, each contractor’s liability for liquidated damages is subject to a cap. Each of our material agreements with contractors is also subject to termination by the contractor prior to completion of construction under certain circumstances, including extended delays (of 100 days or more) caused by force majeure events and our insolvency, breach of material obligations not subject to adjustment by change order, or failure to pay undisputed amounts. Please read “Description of Principal Construction Agreements” for further information.

Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the project or result in a contractor’s unwillingness to perform further work on the project. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, Sabine Pass LNG would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs.

The failure of our contractors to perform under their contracts for any of the reasons described above may extend the date on which our TUA customers are required to begin making payments to us. This delay in payments could have a material adverse effect on our cash flows and results of operations and on our ability to make distributions to you in a timely manner, or at all.

We may experience cost overruns and delays in the completion of Phase 1 or Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal as well as difficulties in obtaining funding for any additional costs, which could have a material adverse effect on our results of operations and ability to make cash distributions to our unitholders.

Our construction costs for Phase 1 and for Phase 2 – Stage 1 may be significantly higher than our current estimates as a result of cost overruns, change orders under existing or future construction contracts, increased component and material costs, escalating labor costs, limited availability of labor, delays in construction and the increased spending to maintain construction schedules. As of December 19, 2006, change orders for $105.7 million have been approved under the Phase 1 EPC agreement with Bechtel. We do not have any prior experience in constructing LNG receiving terminals, and no LNG receiving terminal has been constructed and placed in service in the United States in almost 25 years, as a result of which there are limited benchmarks against which to compare our estimates. If our construction costs are higher than estimated, our cash available for distribution to unitholders may be reduced.

Furthermore, in order to cover not only increased costs but also the cost of a sixth LNG storage tank if requested by Cheniere Marketing under its TUA, we may need to obtain additional funding. If we fail to obtain sufficient funding and Sabine Pass LNG fails to complete Phase 1, our business plan could fail. If Phase 1 is satisfactorily completed but funding is not sufficient for completion of Phase 2 – Stage 1, Sabine Pass LNG will be entitled to receive payments under the TUAs, including the Cheniere Marketing TUA, but Cheniere Marketing may not have access to regasification capacity or other resources or business opportunities sufficient to generate cash flow to fund its required payments to Sabine Pass LNG under the Cheniere Marketing TUA. This could cause Cheniere Marketing to default on its obligations, which could have a material adverse effect on our business, results of operations, financial condition and prospects.

Our ability to obtain debt or equity financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factors beyond our control, such as the status of various capital and industry markets at the time financing is sought. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, if at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, results of operations, financial condition and prospects.

 

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To commission the Sabine Pass LNG receiving terminal, Sabine Pass LNG must purchase and process LNG. Sabine Pass LNG has not previously purchased or processed any LNG.

The Sabine Pass LNG receiving terminal must undergo a commissioning process for its storage tanks and other equipment before commencement of commercial operation. The commissioning process will require a substantial quantity of LNG as well as access to adequate LNG tankers to deliver the LNG.

The costs of this LNG (other than a minor portion we refer to as “heel” LNG) and the tankers are not included in our construction cost estimates, but we have projected the cost to be $157.5 million for purposes of calculating forecasted cash available for distribution to unitholders in this prospectus. Please read “Cash Distribution Policy and Restrictions on Distributions—Forecast of Cash Available for Distribution.” Our actual cost to obtain LNG for the commissioning process could exceed our estimates, and the overrun could be significant.

Sabine Pass LNG faces several principal risks associated with this required purchase of LNG, including the following:

 

    Sabine Pass LNG may be unable to enter into a contract for the purchase of the LNG used for commissioning and may be unable to obtain tankers to deliver such LNG on terms reasonably acceptable to it or at all. Although Sabine Pass LNG expects to contract with Cheniere Marketing to provide the LNG and the tankers, it has not negotiated any such contract at this time with Cheniere Marketing or any other third party;

 

    Sabine Pass LNG will bear the commodity price risk associated with purchasing the LNG, holding it in inventory for a certain 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.

The failure of Sabine Pass LNG to obtain LNG, tankers or both, or be able to finance the purchase of LNG needed for commissioning, would impede the ability to commence commercial operation at the Sabine Pass LNG receiving terminal, which could extend the date on which our TUA customers are required to begin making payments to us. This delay in payments could have a material adverse effect on our business, results of operations, financial condition and prospects.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development of the Sabine Pass LNG receiving terminal could impede completion and have a material adverse effect on us.

The design, construction and operation of LNG receiving terminals are all highly regulated activities. The FERC’s approval under Section 3 of the Natural Gas Act of 1938, or NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to construct and operate the Sabine Pass LNG receiving terminal. Although Sabine Pass LNG has obtained NGA Section 3 authorization to construct and operate the Sabine Pass LNG receiving terminal, such authorization is subject to ongoing conditions imposed by the FERC. Sabine Pass LNG also has not obtained several other material governmental and regulatory approvals and permits required in order to construct and operate Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal, including several under the Clean Air Act and the Clean Water Act from the U.S. Army Corps of Engineers and the Louisiana Department of Environmental Quality. We have no control over the outcome of the review and approval process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any existing or potential interventions or other actions by third parties will interfere with Sabine Pass LNG’s ability to obtain and maintain such permits or approvals. If Sabine Pass LNG is unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in the project. 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.

 

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Hurricanes or other natural disasters could result in a delay in the completion of the Sabine Pass LNG receiving terminal, higher construction costs and the deferral of the dates on which our TUA counterparties are obligated to begin making payments to us.

In August and September of 2005, Hurricanes Katrina and Rita and related storm activity, including windstorms, storm surges, floods and tornadoes, caused extensive and catastrophic damage to coastal and inland areas located in the Gulf Coast region of the U.S. (parts of Texas, Louisiana, Mississippi and Alabama) and certain other parts of the southeastern U.S. 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 totaling approximately $30.6 million.

Future similar storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, delays or cost increases in construction of, or interruption of operations at, the Sabine Pass LNG receiving terminal or related infrastructure.

Risks Relating to Our Cash Distributions

We may not have sufficient cash from operations to enable us to fund the initial quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner and funding of capital expenditures.

We plan to retain cash in a distribution reserve sufficient to fund the initial quarterly distribution through the distribution made in respect of the quarter ending June 30, 2009. After that time, we may not have sufficient available cash each quarter to pay the initial quarterly distribution. The amount of cash that we can distribute on our common units principally will depend upon the amount of cash that we generate from our operations, which will be based on, among other things:

 

    Sabine Pass LNG’s success in completing Phase 1 and Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal, and the timing and cost of completion;

 

    performance by counterparties of their obligations under the TUAs;

 

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

 

    the adequacy of Sabine Pass LNG’s 2% retainage to cover anticipated fuel requirements and natural gas losses; and

 

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

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

 

    the level of capital expenditures that we make, including those for a sixth LNG storage tank if requested by Cheniere Marketing under its TUA, which we have internally estimated could cost in the range of $120 million to $140 million. Sabine Pass LNG will not receive additional revenues in exchange for constructing a sixth LNG storage tank under the Cheniere Marketing TUA;

 

    the restrictions contained in our and our subsidiaries’ debt agreements and our debt service requirements, including the ability of Sabine Pass LNG to pay distributions to us under the indenture governing the Sabine Pass LNG notes as a result of requirements for a $75 million debt service reserve account, a debt payment account and satisfaction of a fixed charge coverage ratio. See “Indebtedness—Indenture—Covenants—Restricted Payments;”

 

    the costs and capital requirements of acquisitions, if any;

 

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    fluctuations in our working capital needs;

 

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

 

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

Sabine Pass LNG may be restricted under the terms of the indenture governing the Sabine Pass LNG notes from making distributions to us and from incurring additional indebtedness under certain circumstances, which may limit our ability to pay or increase distributions to you.

The indenture governing the Sabine Pass LNG notes restricts payments that Sabine Pass LNG can make to us in certain events and limits the indebtedness that Sabine Pass LNG can incur. Please read “Indebtedness.” Prior to Phase 1 Target Completion, as defined in the indenture, which we anticipate will occur in the second quarter of 2008, Sabine Pass LNG will not be permitted to pay any distributions to us. Following Phase 1 Target Completion, Sabine Pass LNG will be 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;

 

     1/6th of the amount of interest due on the Sabine Pass LNG 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 Sabine Pass LNG notes then due and payable has been paid;

 

    taxes payable by Sabine Pass LNG 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 Sabine Pass LNG notes.

In addition, Sabine Pass LNG will only be able to make distributions to us in the event that it could, among other things, incur at least $1.00 of additional indebtedness under the fixed charge coverage ratio test of 2.0 to 1.0 at the time of payment and after giving pro forma effect to the distribution. Please read “Indebtedness—Indenture—Covenants” for the method of calculating the fixed charge coverage ratio.

Sabine Pass LNG will also be prohibited under the indenture governing the Sabine Pass LNG notes 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 Sabine Pass LNG notes;

 

    a failure to pay any principal of, or premium, if any, on the Sabine Pass LNG notes;

 

    a failure by Sabine Pass LNG to comply with various covenants in the indenture governing the Sabine Pass LNG notes;

 

    a failure to observe any other agreement in the indenture governing the Sabine Pass LNG notes 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 million and 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 million that is not discharged or stayed within 60 days following entry;

 

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    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 indenture governing the Sabine Pass LNG notes may inhibit our ability to pay or increase distributions to you.

After March 31, 2009, the fixed charge coverage test contained in the indenture governing the Sabine Pass LNG notes 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.

After March 31, 2009, Sabine Pass LNG will not be 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. See “Indebtedness—Indenture—Covenants” for more detail regarding this calculation. In order to satisfy this fixed charge coverage ratio test after March 31, 2009, we estimate that Sabine Pass LNG’s revenues under its TUAs must aggregate at least approximately $350 million per year. Accordingly, we will not receive cash distributions from Sabine Pass LNG if Sabine Pass LNG does not receive, in addition to the approximately $250 million per year of contracted annual revenues from the Total and Chevron TUAs, substantial revenues under the Cheniere Marketing TUA or from one or more substitute customers.

Cheniere Marketing is a development stage company with a limited operating history, limited capital, no credit rating and an untested business strategy. 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 B 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.

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 GAAP as then in effect and as provided in the indenture governing the Sabine Pass LNG notes. 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 indenture governing the Sabine Pass LNG notes 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 indenture governing the Sabine Pass LNG notes also contains various other covenants that may prevent it from engaging in beneficial transactions, including limitations on Sabine Pass LNG’s ability to:

 

    sell or transfer assets;

 

    incur liens;

 

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    enter into transactions with affiliates;

 

    consolidate, merge, sell or lease all or substantially all of its assets; and

 

    enter into sale and leaseback transactions.

Cost reimbursements and management fees due to our general partner and its affiliates will reduce cash available to pay distributions to you.

Prior to making any distributions on our common units, we will reimburse our general partner’s out-of-pocket costs and pay our general partner an administrative fee of $10 million per year, adjusted for inflation after January 1, 2007, beginning in the first quarter of 2009 for the provision by Cheniere or its affiliates of various general and administrative services for our benefit. In addition, Sabine Pass LNG has agreed to pay approximately $8 million per year, subject to adjustment for inflation, plus cost reimbursements, to affiliates of our general partner in connection with their provision of operating, maintenance, administrative and management services to Sabine Pass LNG and its general partner. Our general partner and its affiliates will also be entitled to reimbursement for all other direct expenses that they incur on our behalf. Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest.” These payments and expenses could adversely affect our ability to pay cash distributions to you.

The amount of cash that we have available for distributions to you 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 will not be able to increase the distributions on our common units unless we are able to make accretive acquisitions.

We will not be able to increase distributions on our common units by generating additional cash flows from Phase 1 and Phase 2 – Stage 1 of 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 must make accretive acquisitions of additional cash-generating assets and operations in order to increase the quarterly distributions on our common units.

Our financial estimates, including our forecast of cash available for distribution, and our Independent Engineer’s conclusions are based on certain assumptions that may not materialize.

The financial estimates that we have included in this prospectus, including under “Summary—Forecast of Cash Available to Pay Distributions” and “Cash Distribution Policy and Restrictions on Distributions—Cash Distributions” are based upon assumptions and information that we believe are reliable as of today. However, these estimates and assumptions are inherently subject to significant business, economic and other uncertainties, many of which are beyond our control. Financial estimates are necessarily speculative in nature, and you should expect that some or all of the assumptions will not materialize. Actual results will probably vary from the estimates, and the variations will likely be material and are likely to increase over time. Consequently, the inclusion of estimates in this prospectus should not be regarded as a representation by us or the underwriters or any other person that the estimated results will actually be achieved. Moreover, we do not intend to update or otherwise revise the estimates to reflect events or circumstances after the date of this prospectus or to reflect the occurrence of unanticipated events. Undue reliance should not be placed on the estimates contained in this prospectus. Our estimates were not prepared with a view toward compliance with the guidelines of the American Institute of Certified Public Accountants. Moreover, no independent accountants compiled or examined the estimates, and, accordingly, our independent accountants do not express an opinion or any other form of assurance with respect to our estimates and assume no responsibility for, and disclaim any association with, the estimates.

 

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In the preparation of its report, the Independent Engineer has relied on assumptions regarding circumstances beyond the control of us or any other person. By their nature, these assumptions are subject to significant uncertainties, and actual results will differ, perhaps materially, from those stated in the Independent Engineer’s report. We cannot give any assurance that these assumptions will prove to be correct. If our actual results are materially less favorable than those shown in the Independent Engineer’s report, or if the assumptions in the Independent Engineer’s report on which we rely for certain of our financial estimates, prove to be incorrect, Sabine Pass LNG’s ability to pay distributions to us, and our ability to pay distributions to our unitholders, may be adversely affected.

Risks Relating to Development and Operation of Our Business

We will be dependent for substantially all of our revenues and cash flows on the TUA counterparties, including Cheniere Marketing, which has a limited operating history, limited capital, no credit rating and an untested business strategy.

We will be entirely dependent on the Chevron, Total and Cheniere Marketing TUAs for operating revenues and cash flows. Each of Chevron and Total will pay approximately $125 million annually when payments under those contracts commence, and Cheniere Marketing will pay approximately $250 million annually commencing in 2009. As discussed above, in order for us to pay the initial quarterly distribution on all of our units, our TUA counterparties must pay these amounts in full. We are also exposed to the credit risk of the guarantors of our customers’ obligations under the TUAs in the event that Sabine Pass LNG must seek recourse under a guaranty, and any nonpayment or nonperformance by the guarantors could reduce the ability of Sabine Pass LNG to pay distributions to us and, in turn, our ability to pay distributions to our unitholders.

Cheniere Marketing has a limited operating history, limited capital, no credit rating and an untested business strategy, and Cheniere has a non-investment grade corporate rating of B from Standard and Poor’s. As a result, Cheniere Marketing and Cheniere have a higher risk of being financially unable to perform on the Cheniere Marketing TUA than either Chevron or Total face with respect to their TUAs. Although each of our 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 otherwise, that risk is 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 has no agreements or arrangements for any supplies of LNG, for any vessels to transport LNG or for the utilization of the capacity that it has contracted for under its TUA with Sabine Pass LNG 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;

 

    the pipeline on which Cheniere Marketing will rely to transport gas from the Sabine Pass LNG receiving terminal to interconnections with other pipelines has not been constructed, and its timely construction is subject to numerous risks, such as weather delays, accidents, difficulty in obtaining construction financing and inability to obtain required rights-of-way or governmental approvals. In addition, Cheniere Marketing has no existing arrangements with other pipelines for transportation of natural gas to customers;

 

    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; and

 

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    Cheniere Marketing engages in trading and hedging activities, which requires posting of collateral with trade counterparties and imposes other liquidity requirements and constraints that may be difficult for Cheniere Marketing to satisfy because it has no credit rating and limited access to capital. In pursuing this business, Cheniere Marketing will take physical ownership of natural gas, which will expose it to losses from fluctuations in commodity prices and could also result in negative cash flows and adverse liquidity effects for Cheniere Marketing.

In pursuing each aspect of its planned business, Cheniere Marketing will encounter intense competition, including competition from major oil companies and other competitors with significantly greater resources. Cheniere Marketing will also compete with our other customers and may compete with Cheniere and its other subsidiaries that are developing or operating other LNG receiving terminals and related infrastructure, including vessels, pipelines and 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 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.

After the Sabine Pass LNG receiving terminal is placed in service, its business will involve significant operational risks.

If Sabine Pass LNG is successful in completing Phase 1 and Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal, Sabine Pass LNG will still face risks associated with operating the facility. These risks will include, but will not be limited to, the following:

 

    the facility’s 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 Sabine Pass LNG or any contracted facility operator or others;

 

    labor disputes; and

 

    weather-related interruptions of operations.

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 will use 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 has no arrangements in place to obtain any such natural gas and will bear the risk of changing prices with respect to additional natural gas that it may need to purchase for fuel.

The inability to import LNG into the U.S. could materially adversely affect our customers, particularly Cheniere Marketing, and our business plans and results of operations if Sabine Pass LNG has to replace TUAs that terminate or expire.

Upon completion of the Sabine Pass LNG receiving terminal, our business will be dependent upon the ability of our customers to import LNG supplies into the U.S. Political instability in foreign countries that have

 

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supplies of natural gas, or strained relations between such countries and the U.S., may impede the willingness or ability of LNG suppliers in such countries to export LNG to the U.S. Such foreign suppliers may also be able to negotiate more favorable prices with other LNG customers around the world than with customers in the U.S., thereby reducing the supply of LNG available to be imported into the U.S. market. Any significant impediment to the ability to import LNG into the U.S. could have a material adverse affect on Sabine Pass LNG’s customers, particularly Cheniere Marketing, and on our business, results of operations, financial condition and prospects. In addition, the quality of LNG available for importation may not meet the quality specifications of the pipelines interconnected with or downstream of the Sabine Pass LNG receiving terminal, and the terminal and its customers do not have plans in place to condition such LNG to meet the pipeline specifications. 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 you.

Failure of sufficient LNG liquefaction capacity to be constructed worldwide could adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions.

Commercial development of an LNG liquefaction facility can take a number of years and requires substantial capital investment. Many factors could negatively affect continued development of LNG liquefaction facilities, including:

 

    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 facility or LNG carrier.

If sufficient LNG liquefaction capacity is not constructed, our customers, particularly Cheniere Marketing, may find it difficult to obtain sufficient utilization of their capacity at the Sabine Pass LNG receiving terminal to support their obligations under their TUAs. A lack of growth in liquefaction capacity may also limit the LNG assets being constructed and therefore, our potential acquisition opportunities, which may limit our ability to increase distributions to you.

A shortage of LNG tankers worldwide could adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions.

We believe that the existing fleet of tankers that is available to transport LNG is inadequate, and the failure to expand LNG tanker capacity would impede our customers’ ability to import LNG into the U.S. The construction and delivery of additional LNG vessels require significant capital, and the availability of the vessels could be delayed to the detriment of our customers because of:

 

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

 

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

 

    changes in governmental regulations or maritime self-regulatory organizations;

 

    work stoppages or other labor disturbances at the shipyards;

 

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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.

Failure of imported LNG to become a competitive source of energy in North America could adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions.

In North America, due mainly to an abundant supply of natural gas, imported LNG has not historically been a major energy source. Cheniere Marketing’s business plan is based, in part, on the belief that LNG can be produced 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 at a lower cost than LNG. In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. As a result, LNG may not become a competitive source of energy in North America. The failure of LNG to become a competitive supply alternative to domestic natural gas, oil and other import alternatives could adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions. In addition, the failure of LNG to become a competitive supply alternative may impede the ability of our customers, particularly Cheniere Marketing, to obtain customers for regasified LNG, which may decrease their revenues and ability to make payments under their TUAs and result in a default of their payment obligations thereunder.

Decreases in the price of natural gas could lead to reduced development of LNG projects worldwide, which could adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions.

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 any of the following factors:

 

    relatively minor changes in the supply of, and demand for, natural gas;

 

    political conditions in international natural gas producing regions;

 

    the extent of domestic production and importation of natural gas in relevant markets;

 

    the level of consumer demand;

 

    weather conditions;

 

    the competitive position of natural gas as a source of energy compared with other energy sources; and

 

    the effect of federal and state regulation on the production, transportation and sale of natural gas.

The willingness of potential customers to contract for regasification capacity would be negatively impacted and, once facilities are in operation, LNG throughput volumes would likely decline if the price of natural gas in North America is, or is forecast to be, lower than the cost to produce and deliver LNG to North American markets. Any significant decline in the price of natural gas could cause the cost of natural gas produced from imported LNG to be higher than domestically produced natural gas. As a result, our customers, particularly Cheniere Marketing, may not be able to procure supplies of LNG or customers for regasified LNG, which may

 

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decrease their revenues and ability to make payments under the TUAs and result in a default of their payments obligations thereunder. Such payment defaults may have a material adverse effect on our business, results of operations, financial condition and prospects. In addition, a decline in the price of natural gas may result in fewer LNG assets being constructed or available for acquisition by us at a given time and, therefore, limit our ability to increase distributions to you.

Cyclical changes in the demand for LNG regasification capacity may adversely affect the performance by our customers, particularly Cheniere Marketing, of their obligations under the TUAs and could reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions.

The economics of LNG terminal operations 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:

 

    significant additions in regasification capacity in North America, as well as European, Asian and other markets, which could divert LNG from the Sabine Pass LNG receiving terminal;

 

    reduced demand for natural gas in North America, which could suppress demand for LNG;

 

    increased natural gas production in North America, which could suppress demand for LNG;

 

    higher prices for LNG in alternative markets such as Europe and Asia, which could divert LNG from the U.S. to those markets;

 

    insufficient LNG production worldwide, which may limit the amount of LNG imported into the U.S.;

 

    cost improvements that allow competitors to offer LNG regasification services at reduced prices;

 

    insufficient LNG tanker supplies, which may limit the ability to import LNG;

 

    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; and

 

    cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

These changes in the economics of LNG terminal operations could materially adversely affect the ability of our 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. If and when the TUAs terminate or expire, unfavorable economic conditions that affect our customers could, in turn, for similar reasons, reduce our operating revenues, cause us operating losses and adversely affect our ability to make or increase distributions. In addition, these cyclical changes may result in fewer LNG assets being constructed or available for acquisition by us at a given time and, therefore, limit our ability to increase distributions to you.

We may experience increased labor costs, and the unavailability of skilled workers or our failure to retain key personnel could hurt the ability to construct and operate the Sabine Pass LNG receiving terminal.

Companies in our industry, including us, 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 construct the Sabine Pass LNG receiving terminal and, upon commencement of commercial operation, to provide our customers with the highest quality service. Our affiliates who hire personnel on our behalf are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult to attract and retain personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs and reducing cash available for distribution. For example, in the aftermaths of

 

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Hurricanes Katrina and Rita, Bechtel and certain subcontractors temporarily experienced a shortage of available skilled labor necessary to meet the requirements of the Phase 1 construction plan. As a result, Sabine Pass LNG agreed to change orders with Bechtel concerning additional activities and expenditures to mitigate the hurricanes’ effects on the completion of Phase 1 of the Sabine Pass LNG receiving terminal. Any increase in our operating costs could materially adversely affect our business, results of operations, financial condition and prospects.

We may face competition from competitors with far greater resources, as well as potential overcapacity in the LNG receiving terminal marketplace.

Many companies are considering or pursuing the development of infrastructure in the domestic LNG market, including major oil and natural gas companies such as Chevron Corporation, ConocoPhillips, ExxonMobil, Royal Dutch/Shell and Total. Other energy companies such as AES, Dominion, El Paso Corporation, Excelerate Energy, McMoRan Exploration, Occidental Petroleum, Sempra, Suez and other public and private companies have also proposed developing or expanding LNG receiving facilities in North America, both onshore and offshore. 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, if and when Sabine Pass LNG’s TUAs terminate or expire, and/or against Cheniere Marketing, which could have a material adverse effect on us.

Industry analysts have predicted that if all of the proposed LNG receiving terminals in North America that have been announced by developers were actually built, there would likely be substantial excess capacity available from such terminals in the future. In addition, the Sabine Pass LNG receiving terminal will likely continue to face competition when and if it is completed, including competition from North American sources of natural gas and onshore, offshore and shipboard LNG regasification facilities. The Sabine Pass LNG receiving terminal will also compete with the Corpus Christi and Creole Trail LNG receiving terminals that Cheniere is proposing to develop and the Freeport LNG receiving terminal in which Cheniere owns a minority interest. If the number of LNG receiving terminals built outstrips demand for natural gas from those terminals, the excess capacity could have a material adverse effect on Cheniere Marketing, or on us in the event Sabine Pass LNG has to replace its TUAs, and on our business, results of operations, financial condition and prospects.

Each of the three TUAs that Sabine Pass LNG has entered into is subject to termination by the contractual counterparty under certain circumstances, and Sabine Pass LNG is dependent on the performance of those counterparties under the TUAs.

Sabine Pass LNG has entered into long-term TUAs with Total, Chevron and Cheniere Marketing. Each of the TUAs contains various termination rights. For example, each counterparty may terminate its TUA if the Sabine Pass LNG receiving terminal experiences a force majeure delay for longer than 18 months, fails to deliver a specified amount of natural gas redelivery nominations or fails to receive or unload a specified number of LNG cargoes. Please read “Business—Customers.” Sabine Pass LNG may not be able to replace these TUAs on desirable terms, or at all, if they are terminated. In the case of each of these TUAs, Sabine Pass LNG is dependent on the respective counterparty’s continued willingness and ability to perform its obligations under the TUAs. If any of these counterparties fails to perform its obligations under its respective TUA, our business, results of operations, financial condition and prospects could be materially adversely affected, even if Sabine Pass LNG was to be ultimately successful in seeking damages from that counterparty or its guarantor for a breach of the TUA.

We will be 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 September 30, 2006, Cheniere and its subsidiaries had 212 full-time employees, who, for the most part, were focused on the development of three LNG receiving terminals and other complementary businesses.

 

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As construction of the Sabine Pass LNG receiving terminal progresses, we will have to hire or otherwise arrange with Cheniere affiliates for new onsite employees to manage the facility. Before the Sabine Pass LNG receiving terminal commences operations, we will also have to hire or otherwise arrange for an entire staff to operate the facility, which will increase the personnel needed to operate the facility from 11 as of December 1, 2006 to 65 in the first quarter of 2008, at an estimated annual cost of approximately $7.6 million. We will rely to a significant extent on the new personnel that we hire or otherwise arrange to perform these functions. As our operations expand, our general partner, Sabine Pass LNG’s general partner and other Cheniere subsidiaries will also have to expand their administrative staffs. If we or those other entities are not able to successfully manage the expansion, our business, results of operations, financial condition and prospects could be materially adversely affected.

Our general partner’s executive officers are also officers of Cheniere and its affiliates. We do not maintain key person life insurance policies on any personnel. Although Cheniere has arranged agreements relating to compensation and benefits with certain of our general partner’s executive officers, 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.

If we do not make acquisitions on economically acceptable terms, our future growth and our ability to increase distributions to you will be limited.

Our ability to grow depends, in part, 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 you 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 adjusted operating surplus per unit within an appropriate timeframe.

Acquisitions involve risks that may adversely affect our business and ability to make distributions to you.

Any acquisition involves 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;

 

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    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 in new business segments or geographic areas.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you 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, your interest in us will be diluted, and distributions to you may be reduced.

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

The construction and operation of the Sabine Pass LNG receiving terminal will be subject to the inherent risks often 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 a significant delay in the timing of commencement of operations and/or in damage to or destruction of the facility or damage to persons and property. In addition, operations at the Sabine Pass LNG receiving terminal and the facilities and tankers of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

In accordance with customary industry practices, we maintain and intend to maintain insurance against some, but not all, of these risks and losses. See “Business—Insurance.” 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 and prospects.

Existing and future U.S. governmental regulation could seriously harm us.

Our business is and will be subject to extensive federal, state and local laws and regulations that regulate the discharge of natural gas, hazardous substances, materials and other compounds into the environment or otherwise relate to the protection of the environment. 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 for pollution or releases of hazardous substances, materials or compounds or otherwise require additional costs or changes in operations that could have a material adverse effect on our business, results of operations, financial condition and prospects. Failure to comply with these laws and regulations may also result in substantial civil and criminal fines and penalties.

Federal laws and regulations such as the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Clean Air Act, or CAA, the Oil Pollution Act, or OPA, and the Clean Water Act, or CWA, and analogous state laws and regulations have regularly imposed increasingly strict requirements for water and air pollution control, hazardous waste and materials management and strict financial responsibility and remedial response obligations. The cost of complying with such environmental legislation could have a material adverse effect on our business, results of operations, financial condition and prospects.

Existing environmental laws and regulations may be revised or reinterpreted or new laws and regulations may be adopted or become applicable to us. Present, as well as future, legislation and regulations could cause

 

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additional expenditures, restrictions and delays in our business and to our planned construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating costs and restrictions could have a material adverse effect on our business, results of operations, financial condition and prospects.

Our lack of diversification could have an adverse effect on our financial condition and results of operations.

All of our revenue is derived from payments under TUAs relating to one asset, the Sabine Pass LNG receiving terminal. 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 sustained military campaigns may adversely impact our business.

The terrorist attacks that took place in the U.S. on September 11, 2001, and subsequent events have created many economic and political uncertainties, some of which may materially adversely affect our business. The continued threat of terrorism and the impact of military and other actions will likely lead to continued volatility in prices for natural gas and could affect the markets for the operations of our LNG suppliers and customers, on which we will be dependent, as well as lead to increased costs incurred by us in our construction project and in implementing security measures against such threats. Furthermore, the U.S. government has issued public warnings that indicate that pipelines and other energy assets might be specific targets of terrorist organizations. These potential targets might include our assets. Our operations could become subject to increased governmental scrutiny that would require increased security measures. Instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations, financial condition and prospects. In addition, if a terrorist incident involving an LNG facility or LNG carrier did occur anywhere in the world, the incident may adversely affect the construction of additional LNG facilities in the United States and other countries or the temporary or permanent closing of various LNG facilities currently in operation.

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.

Following this offering, Cheniere will control 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;

 

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    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;

 

    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 planned Corpus Christi or Creole Trail LNG receiving terminals, its planned 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 before taking advantage of them itself. 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.

 

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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 general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above. Please read “Description of the Common Units—Transfer of Common Units.”

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

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

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

If our unitholders will be unable initially to remove our general partner. Our unitholders will be unable to remove our general partner without the consent of Cheniere Holdings because Cheniere Holdings will own a

 

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sufficient number of common and subordinated units upon completion of this offering 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. Following the closing of this offering, Cheniere Holdings will own approximately 92.3% of our common and subordinated units (approximately 91.2% if the underwriters exercise their option to purchase additional common units in full). 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 the 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.

We will incur increased costs as a result of being a publicly traded company.

We have no history operating as a publicly traded company. As a publicly traded company, we will incur significant legal, accounting and other expenses that we would not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the                  Exchange, have required changes in corporate governance practices of publicly traded companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded company, we are required to have at least three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance, and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

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

 

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than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. At the completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional units, an affiliate of our general partner will own 52.7% of our total 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. For additional information about the limited call right, please read “The Partnership Agreement—Limited Call Right.”

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

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

You will experience immediate and substantial dilution of $18.66 per common unit.

The assumed initial public offering price of $20.00 per common unit exceeds the pro forma net tangible book value of $1.34 per common unit. You will incur immediate and substantial dilution of $18.66 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with generally accepted accounting principles, or GAAP. Please read “Dilution.”

You 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, you 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. Please read “The Partnership Agreement—Limited Liability.”

You 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.

 

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We may issue additional units without your approval, which would dilute your 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.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop.

Prior to this offering, there has been no public market for the common units, and our common units have not previously traded on any exchange or market. After this offering, there will be only publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. In addition, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units. We cannot assure you as to:

 

    the likelihood that an active market will develop for our common units;

 

    the liquidity of any such market;

 

    the ability for you to sell your common units; or

 

    the price that you may obtain for your common units.

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

The initial public offering price for our common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of our common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also 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;

 

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    general economic conditions;

 

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

 

    future sales of our common units; and

 

    other factors described in these “Risk Factors.”

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 entity level taxation by individual states. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity level taxation for state tax purposes, then our cash available for distribution to you 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 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 you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, the cash available for distributions to you 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 you, 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 will be subject to a new entity level tax on the portion 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 you.

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. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne indirectly by our unitholders and our general partner.

You may be required to pay taxes on your share of our taxable income even if you do not receive any cash distributions from us.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you do not receive any cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability which results from your share of our taxable income.

 

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We will make allocations of items of our income, gain, loss and deduction to maintain uniformity of the economic and tax characteristics of our common units. These allocations may require holders to pay taxes on a share of our taxable income without a corresponding cash distribution.

On or after the date that we first make cash distributions to holders of our subordinated units, we will allocate items of income, gain, loss and deduction among the holders of our common units and subordinated units 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 on or after the date that we first make cash distributions to holders of our subordinated units (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 allocation of items of deduction or loss to specific unitholders (for example, the holder of the subordinated units) would effectively reduce the amount of items of deduction or loss that will be allocated to other unitholders. 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.

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

If you sell common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income a unitholder is allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you.

Tax-exempt entities and foreign persons 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) and foreign persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

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.

You 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, you 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

 

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Louisiana and Texas. You 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, you 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 your responsibility to file all United States federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

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. Please read “Material Tax Consequences—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

 

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USE OF PROCEEDS

We estimate that we will receive net proceeds of approximately $96.7 million from this offering, after deducting the underwriting discount and structuring fee on each unit sold and assuming an initial public offering price of $20.00 per common unit. All of our net proceeds will be used to fund a distribution reserve to pay the $0.425 initial quarterly distribution on all common units and general partner units through the distribution made in respect of the quarter ending June 30, 2009.

The selling unitholder will pay the same underwriting discount and structuring fee on each unit sold, as well as all other costs related to this offering. The selling unitholder has granted the underwriters an option to purchase additional common units to cover over-allotments, if any, in connection with this offering. We will not receive any proceeds from any common units sold by the selling unitholder, including proceeds received from any exercise of the underwriters’ option to purchase additional common units.

 

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CAPITALIZATION

The following table shows:

 

    our combined historical capitalization as of September 30, 2006; and

 

    our combined capitalization as of September 30, 2006, as adjusted to reflect:

 

    the issuance of $2,032 million of the Sabine Pass LNG notes in November 2006;

 

    the repayment in November 2006 of the Sabine Pass LNG amended and restated credit facility and the termination of related interest rate swap agreements;

 

    the distribution by Sabine Pass LNG of $380 million to Cheniere Holdings in connection with the issuance of the Sabine Pass LNG notes, which, with other funds, was used for the repayment of Cheniere Holdings’ term loan;

 

    the non-cash contribution by Cheniere Holdings of $35.2 million to Sabine Pass LNG-LP, LLC in November 2006 in settlement of a payable to an affiliate;

 

    the issuance of our common units, subordinated units and general partner units to our general partner and its affiliate; and

 

    the issuance and sale of additional common units in this offering and application of the net proceeds that we receive.

This table is derived from and should be read together with and is qualified in its entirety by reference to, our historical and unaudited combined financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of September 30, 2006  
    

Combined

Actual

   Combined
as Adjusted
 
     (in thousands)  

Cash and cash equivalents:

     

Cash and cash equivalents

   $ 7    $ 7  

Restricted cash and cash equivalents—distribution reserve

     —        96,652  

Restricted cash and cash equivalents—other

     10,837      1,221,727  
               

Total cash and cash equivalents

   $ 10,844    $ 1,318,386  
               

Long-term debt:

     

Amended Sabine Pass LNG credit facility

   $ 351,500    $ —    

Sabine Pass LNG notes due 2013

     —        550,000  

Sabine Pass LNG notes due 2016

     —        1,482,000  

Payable to affiliate

     35,230      —    
               

Total long-term debt

     386,730      2,032,000  
               

Equity:

     

Owners’ equity

     124,638      —    

Held by public:

     

Common units

     —        96,652  

Held by the general partner and its affiliate:

     

Common units

     —        (22,590 )

Subordinated units

     —        (219,761 )

General partner

     —        (5,360 )
               

Total equity (deficit)

     124,638      (151,059 )
               

Total capitalization

   $ 511,368    $ 1,880,941  
               

 

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DILUTION

Dilution is the amount by which the offering price paid by purchasers of common units sold in this offering will exceed the net tangible book value per common unit after the offering. Based on the assumed initial public offering price of $20.00 per common unit, on a pro forma basis as of September 30, 2006, after giving effect to the offering of common units and the related transactions, our net tangible book value was $221.3 million, or $1.34 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit, as illustrated in the following table.

 

Assumed initial public offering price per common unit

      $ 20.00

Pro forma net tangible book value per common unit before the offering(1)

   $ 0.78   

Increase in net tangible book value per common unit attributable to purchasers in the offering

     0.56   
         

Less: Pro forma net tangible book value per common unit after the offering(2)

        1.34
         

Immediate dilution in net tangible book value per common unit to purchasers in the offering

      $ 18.66
         

(1)   Determined by dividing the total number of units (21,206,026 common units, 135,383,831 subordinated units, and 3,302,045 general partner units) to be issued to our general partner and its affiliate for the contribution of the equity interests in the limited partner and general partner of Sabine Pass LNG into the net tangible book value of the contributed assets.
(2)   Determined by dividing the total number of units (26,416,357 common units, 135,383,831 subordinated units, and 3,302,045 general partner units) to be outstanding after the offering into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliate and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.

 

     Units Acquired     Total
Consideration
 
     Number    Percent     Amount    Percent  
     (in millions)  

General partner and its affiliate(1)(2)

   152.6    92.4 %   $ 124.6    33.3 %

New investors

   12.5    7.6 %     250.0    66.7 %
                        

Total

   165.1    100.0 %   $ 374.6    100.0 %
                        

(1)   Upon consummation of the transactions contemplated by this prospectus, our general partner and its affiliate will own 13,916,357 common units, 135,383,831 subordinated units and 3,302,045 general partner units.
(2)   The assets contributed by our general partner and its affiliate were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliate, as of September 30, 2006, was $124.6 million.

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “—Assumptions and Considerations” below. In addition, you should read “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

General

Rationale for Our Cash Distribution Policy

For the Period Through June 30, 2009

We are a development stage company without any revenues, operating cash flows or operating history. We do not expect that revenues from our TUAs with Total and Chevron will begin until the second and third quarter of 2009, respectively. Therefore, we do not expect to generate sufficient cash from operations to fund distributions to our unitholders until the third quarter of 2009. As a result, we will set aside $96.7 million from the net proceeds of this offering as a distribution reserve to pay the $0.425 initial quarterly distribution per common unit for all common units and general partner units through the distribution made in respect of the quarter ending June 30, 2009. Distributions to our unitholders from the distribution reserve will be a return of your investment. Please read “How We Make Cash Distributions—Distributions from Capital Surplus—Effect of a Distribution from Capital Surplus.”

The distribution reserve will be treated as restricted cash and will be invested in short-term money market securities or U.S. treasuries. In the event that we issue additional common units prior to June 30, 2009, we will use a portion of the net proceeds to increase the distribution reserve by an amount that our general partner, with the concurrence of the conflicts committee of its board of directors, determines is required to fund the initial quarterly distribution for such additional common units and related general partner units from their date of issuance through the distribution made in respect of the quarter ending June 30, 2009. Any amount remaining in the distribution reserve on August 15, 2009 will be distributed to Cheniere Holdings. We may distribute amounts in the distribution reserve to Cheniere Holdings prior to August 15, 2009 if our general partner, with the concurrence of its conflicts committee of its board of directors, determines that such reserves are not necessary to provide for distributions on all of our common units and general partner units for any quarter ending on or prior to June 30, 2009. If we generate cash from operations during the period from the closing of this offering to June 30, 2009, we will make quarterly distributions for our common units from such cash generated from operations and, if the amount of such cash is insufficient to make the full quarterly distribution, from amounts in the distribution reserve.

For the Period After June 30, 2009

Beginning in the third quarter of 2009, the combined cash flow received from the Total and Chevron TUAs is expected to be sufficient to cover all annual debt service on the Sabine Pass LNG notes, which will be approximately $151 million, and all other annual operating costs of the Sabine Pass LNG receiving terminal, which will be approximately $48 million for the four consecutive quarters ending June 30, 2010. The remaining funds from Total and Chevron will be sufficient for us to pay the operating expenses of our partnership and the initial quarterly distribution on all of our common units and general partner units so long as these funds are distributable under the indenture governing the Sabine Pass LNG notes.

We will receive $5 million per month under the Cheniere Marketing TUA commencing with Phase 1 commercial operation, which we expect will occur in April 2008. We will not receive the full contracted payments from Cheniere Marketing of approximately $21 million per month until the first quarter of 2009. These payments from Cheniere Marketing are expected to be sufficient to cover the initial quarterly distribution on the subordinated units beginning in the third quarter of 2009 but will not be sufficient to permit an increase in the common unit distribution above the initial quarterly distribution.

 

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Our cash distribution policy beginning in the third quarter of 2009 will reflect a basic judgment that our unitholders will be better served by our distributing our cash available after expenses and reserves rather than retaining it. Because we are not subject to entity level federal income tax, we will have more cash to distribute to you than would be the case were we subject to tax. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.

Limitations on Our Ability to Pay Quarterly Distributions After June 30, 2009

There is no guarantee that unitholders will receive quarterly distributions from us for the period after June 30, 2009. Our distribution policy may be changed at any time and is subject to certain restrictions and uncertainties, including:

 

    Our ability to pay distributions to our unitholders will depend on the performance of Sabine Pass LNG and its ability to distribute funds to us. In general, Sabine Pass LNG may make distributions under its indenture if:

 

    no default or event of default under the indenture has occurred and is continuing or would occur as a consequence of such distribution; and

 

    Sabine Pass LNG has successfully completed Phase 1 Target Completion (as defined in the indenture governing the Sabine Pass LNG notes), which we currently expect to occur during the second quarter of 2008; and

 

    Sabine Pass LNG would, at the time of such distribution and after giving pro forma effect thereto as if such distribution had been made at the beginning of the applicable four-quarter period (or if fewer than four fiscal quarters have elapsed since the achievement of Phase 1 Target Completion, the number of full fiscal quarters that have elapsed), have been permitted to incur at least $1.00 of additional indebtedness pursuant to the 2.0 to 1.0 fixed charge coverage ratio test described in the indenture; and

 

    Sabine Pass LNG has on deposit in a debt payment account an amount equal to (i) the aggregate amount of interest on the Sabine Pass LNG notes due on the immediately succeeding interest payment date, multiplied by (ii) the number of months passed since the preceding interest payment date, divided by (iii) six; and

 

    Sabine Pass LNG has on deposit in a debt service reserve account an amount no less than the amount required to make the interest payments on the Sabine Pass LNG notes on the next succeeding interest payment date.

For more information on the Sabine Pass LNG indenture, please read “Indebtedness–Indenture.”

 

    We may lack sufficient cash to pay distributions to our unitholders due to a number of factors that could adversely affect us. Please read “Risk Factors” for more information regarding these factors.

 

    Our general partner has broad discretion to establish reserves for the prudent conduct of our business, and the establishment of those reserves could result in a reduction of our cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy.

 

    Even if our cash distribution policy is not modified, the amount of distributions that we pay under our cash distribution policy and the decision to pay any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

 

   

Although our partnership agreement requires us to distribute our available cash, our partnership agreement may be amended. During the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of nonaffiliated common unitholders. However, our partnership agreement can be amended with the approval of a majority of the outstanding common units after the subordination period has ended. At the closing of this offering, our general partner and its

 

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affiliates will own approximately 52.7% of the outstanding common units (49.2% if the underwriters exercise their option to purchase additional common units) and 100% of the outstanding subordinated units.

 

    Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

Our Cash Distribution Policy May Limit Our Ability to Grow

We will distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial borrowings and issuances of debt or equity securities, to fund our acquisition and capital investment expenditures. The incurrence of additional commercial borrowings or other debt to finance our operations would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders. If we are unable to finance growth externally, our cash distribution policy could significantly impair our ability to grow.

There are no limitations in our credit facility or, after the subordination period, in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. In the event that we issue additional common units prior to June 30, 2009, we will use a portion of the net proceeds to increase the distribution reserve by an amount that our general partner, with the concurrence of the conflicts committee of its board of directors, determines is required to fund the initial quarterly distribution for such additional common units and related general partner units from their date of issuance through the distribution made in respect of the quarter ending June 30, 2009. To the extent we issue additional units after June 30, 2009, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit.

Cash Distributions

Overview

The amount of the initial quarterly distribution is $0.425 per unit, or $1.70 per year. The amount of cash needed to pay the initial quarterly distribution on all of the common units, subordinated units and general partner units to be outstanding immediately after this offering for one quarter and for four quarters will be approximately:

 

    

Number of Units

  

One

Quarter

   Four Quarters

Public Common Units

   12,500,000    $ 5,312,500    $ 21,250,000

Cheniere and Affiliates Common units

   13,916,357      5,914,452      23,657,807

Cheniere and Affiliates Subordinated units

   135,383,831      57,538,128      230,152,513

General Partner Units

   3,302,045      1,403,369      5,613,476
                  

Total

   165,102,233    $ 70,168,449    $ 280,673,796
                  

Our Initial Distribution Rate

For each calendar quarter through the quarter ending June 30, 2009, we will make cash distributions of $0.425 per unit, or $1.70 per year, on all outstanding common units and general partner units using cash from the $96.7 million distribution reserve that will be funded with proceeds from this offering. We will make these quarterly cash distributions within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2007, to unitholders of record on the applicable record date. We will adjust the initial quarterly distribution for the period from the closing of this offering through March 31, 2007 based on the actual length of the period. We believe that following the completion of the offering, we will have sufficient available cash in the distribution reserve to allow us to pay the full initial quarterly distribution on all of our outstanding common units and general partner units for each quarter through the quarter ending June 30, 2009.

 

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Until the end of the subordination period, before we make any quarterly distributions to subordinated unitholders, our common unitholders are entitled to receive payment of the full initial quarterly distribution plus any arrearages from prior quarters. Please read “How We Make Cash Distributions—Subordination Period.” However, we cannot guarantee that we will pay the initial quarterly distribution on the common units in any quarter after June 30, 2009.

As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. The general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest.

In the sections that follow, we present in detail the basis for our belief that we will be able:

 

    to pay the initial quarterly distribution on all of our outstanding common units and general partner units for each quarter through the quarter ending June 30, 2009; and

 

    to pay the initial quarterly distribution on all outstanding units, including both common units and subordinated units, as well as related distributions to our general partner, for each of the four consecutive quarters ending June 30, 2010.

Financial Forecast for the Period from the Closing of this Offering Through June 30, 2010

Set forth below is a financial forecast of the expected revenues, EBITDA and cash available for distribution for Cheniere Energy Partners, L.P. for the period from the closing of this offering through June 30, 2010. Our financial forecast presents, to the best of our knowledge and belief, the expected revenues, EBITDA and cash available for distribution for Cheniere Energy Partners L.P. for the forecast period. EBITDA is calculated as Sabine Pass LNG’s aggregate TUA revenues less Sabine Pass LNG’s non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes.

Our financial forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the period from the closing of this offering through June 30, 2010. The footnotes to the financial forecast below describe numerous assumptions and considerations that we believe are significant to our financial forecast. We believe our actual revenues and cash flows will approximate those reflected in our financial forecast; however, we can give you no assurance that our forecast results will be achieved. There will likely be differences between our forecast and the actual results and those differences could be material. If the forecast is not achieved, we may not be able to pay cash distributions on our common units at the initial distribution rate stated in our cash distribution policy. For all quarters ending on or before June 30, 2009, we will use funds from our distribution reserve to pay the initial quarterly distribution of $0.425 per unit on all of our outstanding common units, as well as related distributions to our general partner. In order to fund distributions to our unitholders at our initial quarterly rate of $0.425 per common unit for the twelve months ending June 30, 2010, our cash available for distribution for the twelve months ending June 30, 2010 must be at least $280.7 million. As set forth in the table on the following pages, we estimate that our cash available for distribution for this period will be approximately $294.7 million.

After this offering, we do not intend to make public projections as to future sales, earnings or other results. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, and presents, to the best of management’s knowledge and belief, our expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

 

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Neither our independent registered public accounting firm, nor any other registered public accounting firm, has compiled, examined or performed any procedures with respect to the prospective financial information contained below, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information.

Please read the footnotes below for a discussion of the material assumptions underlying our belief that we will be able to generate sufficient cash available to pay distributors for the forecast period. Our belief is based on those assumptions and reflects our judgment, as of the date of this prospectus, regarding the conditions that we expect to exist and the course of action that we expect to take over the estimation period. The assumptions that we disclose below are those that we believe are significant to our ability to generate sufficient cash available to pay distributions for the forecast period. If our estimates prove to be materially incorrect, we may not be able to pay the full initial quarterly distribution or any amount on our outstanding common and subordinated units.

When considering this forecast, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus. Any of these risk factors or the other risks discussed in this prospectus could cause our financial condition and consolidated results of operations to vary significantly from those set forth in the table below. In addition, we do not undertake any obligation to release publicly the results of any future revisions that we may make to these estimates or to update these estimates to reflect events or circumstances after the date of this prospectus. Therefore, we caution you not to place undue reliance on this information.

 

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Cheniere Energy Partners, L.P.

Forecast of Cash Available for Distribution

(in millions, except per unit amounts)

 

   

 

 

Closing Until Phase 1 Commercial

Operation

        
    2007         
    Q1      Q2      Q3      Q4      Q1  

Sabine Pass LNG, L.P.:

             

TUA Revenues(6)

             

Total TUA(7)

  $ —        $ —        $ —        $ —        $ —    

Chevron TUA(7)

    —          —          —          —          —    

Cheniere Marketing TUA(8)

    —          —          —          —          —    
                                           

Aggregate TUA Revenues

  $ —        $ —        $ —        $ —        $ —    

Deferred Revenues(9)

    —          —          —          —          —    

Operating Expenses(10)

    (3.8 )      (2.4 )      (3.3 )      (3.0 )      (8.7 )

Assumed Commissioning Costs(11)

    —          —          —          —          (0.5 )

State and Local Taxes(12)

    —          —          —          —          —    
                                           

Sabine Pass LNG EBITDA(13)

  $ (3.8 )    $ (2.4 )    $ (3.3 )    $ (3.0 )    $ (9.2 )
                                           

Capital Expenditures

             

Construction Capital Expenditures(14)

  $ (155.7 )    $ (121.0 )    $ (100.5 )    $ (90.6 )    $ (63.9 )

Construction Account Disbursements (Construction Capital)(15)

    155.7        121.0        100.5        90.6        63.9  

Construction Account Disbursements (Operating Expenses)(15)

    3.8        2.4        3.3        3.0        9.2  

(Interest Earned on Construction Account)(15)

    —          4.2        5.9        4.8        3.6  

(Ending Balance in Construction Account)(15)

    607.4        488.3        390.4        301.5        232.0  

Maintenance Capital Expenditures(16)

    —          —          —          —          —    

Debt Service

             

Interest on Notes

  $ —        $ (75.5 )    $ —        $ (75.5 )    $ —    

Debt Payment Account Funding (17)

    —          —          —          —          —    

Interest Payments Funded from Debt Payment Account

    —          —          —          —          —    

Interest Payments Funded from Const. Period Debt Service Reserve Account

    —          75.5        —          75.5        —    

(Interest Earned on Construction Period Debt Service Reserve Account)(18)

    4.6        4.4        3.8        3.6        2.9  

(Ending Balance in Construction Period Debt Service Reserve Account)

    359.4        291.5        295.3        223.4        226.3  

Permanent Debt Service Reserve Funding (17)

    —          —          —          —          —    
                                           

Cash Distributable to Us

  $ —        $ —        $ —        $ —        $ —    
                                           

Cheniere Energy Partners, L.P.

             

Cash Received from Sabine Pass LNG

  $ —        $ —        $ —        $ —        $ —    

Operating Expenses(19)

    —          (0.6 )      (0.6 )      (0.6 )      (0.6 )

Advance from Cheniere Energy Inc.(19)

    —          0.6        0.6        0.6        0.6  

Distribution Reserve

             

(Beginning Balance in Distribution Reserve)

  $ —        $ 96.7      $ 86.5      $ 76.1      $ 65.7  

(Interest Earned or Distribution Reserve)(20)

    —          1.3        1.1        1.0        0.9  

Common Unit Distribution

    —          (11.2 )      (11.2 )      (11.2 )      (11.2 )

General Partner Distribution

    —          (0.2 )      (0.2 )      (0.2 )      (0.2 )

Ending Balance in Distribution Reserve

    96.7        86.5        76.1        65.7        55.1  
                                           

Cash Available to Pay Distributions

  $ —        $ 11.5      $ 11.5      $ 11.5      $ 11.5  
                                           

Anticipated Cash Distributions

  $ —        $ 11.5      $ 11.5      $ 11.5      $ 11.5  

Anticipated Cash Distributions Per Unit:

             

Common Units

  $ —        $ 0.425      $ 0.425      $ 0.425      $ 0.425  

Subordinated Units

    —          —          —          —          —    

General Partner Units

    —          0.069        0.069        0.069        0.069  

 

Note:   Italicized amounts are provided for informational purposes. They do not affect the total and subtotals of amounts not in italics.

 

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Phase 1 Commercial

Operation

through Phase 1

Completion

(2.6 Bcf/d)

   

Phase 1 Completion through

Phase 2 – Stage 1

Completion

(4.0 Bcf/d)

   

Phase 2 –

Stage 1 Completion

(4.0 Bcf/d)

 

2008

   

2009

    2010  
  Q2(1)         Q3(2)       Q4     Q1(3)     Q2(4)     Q3(5)     Q4     Q1     Q2  
               
               
$ —       $ —       $ —       $ —       $ 31.3     $ 31.6     $ 31.6     $ 31.0     $ 31.3  
  —         —         —         —         —         32.8       32.8       32.0       32.4  
  15.8       16.0       16.0       63.0       63.7       64.4       64.4       63.1       63.8  
                                                                     
$ 15.8     $ 16.0     $ 16.0     $ 63.0     $ 95.0     $ 128.8     $ 128.8     $ 126.1     $ 127.5  
  —         —         —         —         (0.5 )     (1.0 )     (1.0 )     (1.0 )     (1.0 )
  (8.7 )     (8.7 )     (8.7 )     (8.6 )     (9.1 )     (9.1 )     (9.1 )     (9.3 )     (9.3 )
  (0.4 )     —         —         —         —         —         —         —         —    
  (0.9 )     (0.9 )     (0.9 )     (1.3 )     (2.4 )     (2.4 )     (2.4 )     (2.5 )     (2.5 )
                                                                     
$ 5.8     $ 6.4     $ 6.4     $ 53.1     $ 83.0     $ 116.3     $ 116.3     $ 113.3     $ 114.7  
                                                                     
               
$ (60.5 )   $ (34.9 )   $ (33.9 )   $ (23.1 )   $ (20.1 )   $ (10.2 )   $ (6.6 )   $ —       $ —    
  60.5       34.9       33.9       23.1       20.1       10.2       6.6       —         —    
  9.1       8.7       8.7       —         —         —         —         —         —    
  2.7       2.0       1.4       0.9       0.7       0.5       0.3       0.3       0.3  
  165.0       123.4       82.2       59.9       40.6       30.9       24.7       25.0       25.3  
  —         —         —         (0.4 )     (0.4 )     (0.4 )     (0.4 )     (0.4 )     (0.4 )
               
$ (75.5 )   $ —       $ (75.5 )   $ —       $ (75.5 )   $ —       $ (75.5 )   $ —       $ (75.5 )
  (14.9 )     (15.1 )     (15.1 )     (45.3 )     (37.8 )     (37.8 )     (37.8 )     (37.8 )     (37.8 )
  9.9       —         30.1       —         75.5       —         75.5       —         75.5  
  65.6       —         45.5       123.7       —         —         —         —         —    
  2.7       2.2       2.0       1.6       —         —         —         —         —    
  163.4       165.6       122.1       —         —         —         —         —             
  —         —         —         (75.5 )     —         —         —         —         —    
                                                                     
$ —       $ —       $ —       $ 55.6     $ 44.8     $ 78.1     $ 78.1     $ 75.2     $ 76.6  
                                                                     
               
$ —       $ —       $ —       $ 55.6     $ 44.8     $ 78.1     $ 78.1     $ 75.2     $ 76.6  
  (0.6 )     (0.6 )     (0.6 )     (3.3 )     (3.3 )     (3.3 )     (3.3 )     (3.4 )     (3.4 )
  0.6       0.6       0.6       —         —         —         —         —         —    
               
$ 55.1     $ 44.4     $ 33.5     $ 22.5     $ 11.3     $ —       $ —       $ —       $ —    
  0.7       0.6       0.4       0.3       0.1       —         —         —             
  (11.2 )     (11.2 )     (11.2 )     (11.2 )     (11.2 )     —         —         —         —    
  (0.2 )     (0.2 )     (0.2 )     (0.2 )     (0.2 )     —         —         —         —    
  44.4       33.5       22.5       11.3       —         —         —         —         —    
                                                                     
$ 11.5     $ 11.5     $ 11.5     $ 63.8     $ 53.0     $ 74.8     $ 74.8     $ 71.8     $ 73.2  
                                                                     
$ 11.5     $ 11.5     $ 11.5     $ 63.8     $ 53.0     $ 70.2     $ 70.2     $ 70.2     $ 70.2  
               
$ 0.425     $ 0.425     $ 0.425     $ 0.425     $ 0.425     $ 0.425     $ 0.425     $ 0.425     $ 0.425  
  —         —         —         0.379       0.301       0.425       0.425       0.425       0.425  
  0.069       0.069       0.069       0.386       0.321       0.425       0.425       0.425       0.425  

 

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(1)   We expect to achieve Phase 1 commercial operation in April 2008. From the date that we achieve Phase 1 commercial operation through December 2008, Cheniere Marketing will pay $5 million per month plus tax reimbursements under its TUA with Sabine Pass LNG.
(2)   We expect to complete Phase 1 with three LNG storage tanks and a sendout rate of 2.6 Bcf/d, which we refer to as Phase 1 completion, during the third quarter of 2008. Under its EPC contract with Sabine Pass LNG, Bechtel has guaranteed Phase 1 substantial completion by December 20, 2008.
(3)   Provided we have achieved Phase 1 commercial operation, Cheniere Marketing will be required under its TUA with Sabine Pass LNG to pay monthly capacity reservation fees aggregating approximately $255.5 million per year, starting January 2009. These monthly payments will be required on what is referred to as a “take or pay” basis, which means that the customer will be obligated to pay the full contracted amount of monthly fees whether or not it uses the Sabine Pass LNG receiving terminal.
(4)   Provided we have achieved the level of commercial operability required under Total’s TUA, which we expect will occur during the third quarter of 2008, Total will be required under its TUA with Sabine Pass LNG to pay monthly capacity reservation fees aggregating approximately $125.5 million per year, starting April 2009. These monthly payments will be required on a “take or pay” basis.
(5)   Provided we have achieved the level of commercial operability required under Chevron’s TUA, which we expect will occur during the third quarter of 2008, Chevron will be required under its TUA with Sabine Pass LNG to pay monthly capacity reservation fees aggregating approximately $129.9 million per year, starting not later than July 2009. These monthly payments will be required on a “take or pay” basis.
(6)   Monthly capacity reservation fees under the TUAs are based on the aggregate MMbtu receipt capacity reserved by each customer and will include a fixed fee component equivalent to approximately $0.28 per MMbtu and an additional fee component equivalent to approximately $0.04 per MMbtu that is subject to adjustment for annual consumer price index inflation, which we assume will be 2.5% annually. The aggregate MMbtu reserved capacity is equivalent to approximately 1.0 Bcf/d for each of Total and Chevron from inception of payments under its TUA and is equivalent to approximately 2.0 Bcf/d for Cheniere Marketing when we achieve Phase 2 – Stage 1 completion. We will achieve Phase 2 – Stage 1 completion when we complete two additional LNG storage tanks and achieving full operability of the Sabine Pass LNG receiving terminal at approximately 4.0 Bcf/d. We expect to achieve Phase 2 – Stage 1 completion in the third quarter of 2009. Also included in TUA revenues are reimbursements by TUA customers of state and local taxes paid by Sabine Pass LNG (see footnote (12)). In addition, under each customer’s TUA, Sabine Pass LNG is entitled to take an in-kind “retainage” equal to 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 and to cover natural gas unavoidably lost at the Sabine Pass LNG receiving terminal. We have assumed that Sabine Pass LNG will not have any revenue from retainage LNG and will not incur any cost to provide fuel to revaporize LNG for sendout, to provide self-generated power and to cover natural gas unavoidably lost at the Sabine Pass LNG receiving terminal.
(7)   Each of Total and Chevron has previously paid $20 million of advance capacity reservation fees to Sabine Pass LNG. These payments will be recognized as deferred revenues and will reduce cash payments by each customer by $2 million per year in each of the first ten years under its TUA. TUA revenues from each of Total and Chevron include $2 million per year of non-cash deferred revenues.
(8)   Cheniere Marketing has agreed to relinquish up to 200 MMcf/d of its reserved capacity (and proportionately reduce the monthly fee) under its TUA if required to allow Sabine Pass LNG to satisfy its obligations under a TUA that it may potentially enter into with J&S Cheniere, S.A., as more fully discussed in “Business—Customers—Cheniere Marketing TUA.” We have assumed that any assignment to J&S Cheniere will not affect our forecast.
(9)   Non-cash deferred revenues of $2 million per year are deducted from TUA revenues from each of Total and Chevron in calculating EBITDA.
(10)  

Sabine Pass LNG’s combined operating expenses and maintenance capital expenditures have been estimated by us and the Independent Engineer at approximately $36.6 million for the calendar year 2010 in order to support receiving terminal operations at 2.0 Bcf/d, the minimum level required to perform Sabine Pass LNG’s obligations under both the Total TUA and the Chevron TUA. We and the Independent

 

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Engineer have also estimated that Sabine Pass LNG’s combined operating expenses and maintenance capital expenditures will increase by approximately $2.1 million to approximately $38.7 million for the calendar year 2010 in order to support receiving terminal operations at 4.0 Bcf/d. Each of these estimates includes $8.3 million of fees and expenses payable under agreements with Cheniere affiliates for services necessary to operate and maintain the Sabine Pass LNG receiving terminal. In preparing our forecast, we have assumed operating expenses and maintenance capital expenditures as estimated to support operations at the 2.0 Bcf/d level beginning January 1, 2008 and at the 4.0 Bcf/d level beginning April 1, 2009 upon commencement of the Total TUA. We have separated out $1.5 million per year from operating expenses and classified that amount as maintenance capital expenditures (see footnote (16)). We have assumed Sabine Pass LNG operating expenses (net of the $1.5 million of maintenance capital expenditures) of $37.2 million for the calendar year 2010. We have assumed inflation of 2.5% in 2008 and 2009 in estimating operating expenses for those years. Please read the report of the Independent Engineer attached as Appendix B to this prospectus for more information.

(11)   Sabine Pass LNG must obtain LNG in order to commission its receiving terminal. We have assumed that Sabine Pass LNG will obtain three 3.0 Bcf cargoes of LNG in the first quarter of 2008 at an aggregate cost of $85.5 million ($9.50 per MMbtu, which was the average NYMEX price on November 28, 2006 for contracts to purchase natural gas in the first quarter of 2008) and three additional 3.0 Bcf cargoes of LNG in the second quarter of 2008 at an aggregate cost of $72.0 million ($8.00 per MMbtu, which was the average NYMEX price on November 28, 2006 for contracts to purchase natural gas in the second quarter of 2008). We have assumed that we will not make any profit or incur any loss in reselling the natural gas produced from these six cargoes of LNG. Our assumed commissioning costs shown in the table consist solely of interest costs to finance purchases of these six LNG cargoes and assumes an interest rate of 7.0% per annum. In calculating interest cost, we have further assumed that we are in possession of, on average, one cargo on each day in the first and second quarters of 2009.
(12)   Sabine Pass LNG will pay a 4% usage tax on LNG consumed in plant operations. We have estimated the amount of this tax assuming that Sabine Pass LNG’s full 2% “retainage” of LNG will be consumed in plant operations. Sabine Pass LNG will also pay ordinary ad valorem taxes on its plant assets. Sabine Pass LNG has obtained a 100% deferral of those ad valorem taxes through 2018. In order to assist the taxing authorities to fund reconstruction of infrastructure that was damaged by hurricanes in 2005 and that supports development and operation of the Sabine Pass LNG receiving terminal, Sabine Pass LNG has offered to make payments in lieu of taxes to the extent of approximately $2.5 million annually for ten years. We have assumed that this offer will be accepted and that payments will begin in 2009. The TUA customers are obligated to reimburse Sabine Pass LNG for all usage and ad valorem taxes (see footnote (6)), provided that Sabine Pass LNG will assume half of Total’s ad valorem tax obligation subject to a cap of $3.9 million.
(13)   Sabine Pass LNG’s EBITDA is calculated as aggregate TUA revenues less non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes . See “—Non-GAAP Financial Measure” below for more information.
(14)   Construction capital expenditures represent our current estimates of the amounts and timing of the capital expenditures that will be required to achieve Phase 1 commercial operation, Phase 1 completion and full Phase 2 – Stage 1 operability on the schedules specified in footnotes (1), (2) and (6). The base amount of LNG, referred to as “heel” LNG, that must be retained in the Sabine Pass LNG receiving terminal in order to maintain requisite cryogenic temperatures after commissioning of all of Phase 1 and Phase 2 – Stage 1 has been included in the construction budget and will be funded from the construction account described in footnote (15). Sabine Pass LNG may also be required to construct a sixth LNG storage tank for the benefit of Cheniere Marketing within four years after notification from Cheniere Marketing. We have assumed that no funds are required to be expended prior to July 1, 2010 in respect of this potential sixth tank. We have internally estimated that the cost of the sixth tank could be in the range of $120 to $140 million.
(15)  

In connection with its issuance of $2,032 million of notes in November 2006, Sabine Pass LNG deposited approximately $886.7 million into a construction account to fund completion and commissioning costs of Phase 1 and Phase 2 – Stage 1 of its receiving terminal, as well as other incidental expenses, including taxes and operating fees and expenses. We estimate that approximately $24.7 million of interest earned on

 

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amounts in the construction account will have been transferred from the construction account and be unexpended funds available for distribution when we have completed Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal. We have assumed that funds on deposit in the construction account will earn interest at 5.25% per year. Under the indenture governing the Sabine Pass LNG notes, the first $20 million of such interest earnings must be transferred to a construction period debt service reserve account described in footnote (18).

(16)   Maintenance capital expenditures estimated by us at $1.5 million per year beginning in 2009, escalating with inflation at 2.5% annually thereafter. This amount does not include natural gas turbine generator maintenance costs, which are covered by a third-party contract fee included in operating expenses. Maintenance capital expenditures in the forecast period are low because the receiving terminal will be brand new, will require little maintenance and will initially be protected by warranties. These maintenance capital costs have been separated out from the Independent Engineer’s estimates and reclassified as described in footnote (10).
(17)   Under the indenture governing the Sabine Pass LNG notes, Sabine Pass LNG may not make distributions to us until certain conditions are satisfied. The indenture requires that Sabine Pass LNG apply its net operating cash flow (i) first, to fund with monthly deposits its next semiannual payment of approximately $75.5 million of interest on its notes, and (ii) second, to fund a one-time, permanent debt service reserve fund equal to one semiannual interest payment of approximately $75.5 million on its notes. Distributions to us from Sabine Pass LNG will be permitted only after Phase 1 Target Completion, as defined in the indenture, or such earlier date as project revenues are received by Sabine Pass LNG, upon satisfaction of the foregoing funding requirements and after satisfaction of a fixed charge coverage ratio test and other conditions specified in the indenture. Please read “Indebtedness—Indenture” for more information. We will not receive the full contracted payments from the Cheniere Marketing TUA until the first quarter of 2009 and, accordingly, do not expect that Sabine Pass LNG will make distributions to us until the first quarter of 2009.
(18)   In connection with its issuance of the Sabine Pass LNG notes in November 2009, Sabine Pass LNG also deposited $335 million into a construction period debt service reserve account. This account, together with $20 million of interest earned on amounts on deposit in the construction account that will be transferred to the construction period debt service reserve account as described in footnote (17), and together with interest earned on amounts on deposit in the construction period debt service reserve account, is intended to be sufficient to pay all scheduled semiannual payments of interest on the Sabine Pass LNG notes through the payment due May 30, 2009. We have assumed that funds on deposit in the construction period debt service reserve account will earn interest at 5.25% per year.
(19)   We have estimated that our partnership will incur costs of approximately $2.5 million per year, adjusted for inflation at 2.5% per year after January 1, 2007, for tax compliance and publicly traded partnership tax reporting, accounting, SEC reporting and other costs of operating as a publicly traded partnership. Through 2008, we will fund these costs with funds advanced to us from Cheniere, after which time we will use available cash to pay such expenses and, after payment of the initial quarterly distribution on all units, to reimburse Cheniere. In addition, we will pay a Cheniere affiliate a fixed amount of $10 million per year, adjusted for inflation at 2.5% per year after January 1, 2007, beginning in the first quarter of 2009 for providing general and administrative services to our partnership.
(20)   At completion of this offering, our partnership will fund a distribution reserve of approximately $96.7 million. The distribution reserve, together with interest earned on funds on deposit in the distribution reserve and operating cash flows, will be used to pay the $0.425 initial quarterly distribution per common unit for all common units and general partner units through the distribution in respect of the quarter ending June 30, 2009. We have assumed that unexpended funds in the distribution reserve will earn interest at 5.25% per year.

 

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Assumptions and Considerations

The footnotes to the financial forecast set forth above describe the numerous assumptions and considerations that we believe are significant to our financial forecast. While we believe that these assumptions are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant risks and uncertainties, including those described in “Risk Factors” or in the footnotes to the financial forecast included above, that could cause actual results to differ materially from those we anticipate. We cannot give any assurance these assumptions or assessments are correct. If any of our assumptions are not correct, or if we inaccurately assess any of these considerations, the actual available cash that we generate could be substantially less than that currently expected and could, therefore, be insufficient to permit us to pay distributions to our unitholders, in which event the market price of the common units may decline materially.

In the preparation of its report attached to this prospectus as Appendix B, the Independent Engineer has relied on assumptions regarding circumstances beyond the control of us or any other person. By their nature, these assumptions are subject to significant uncertainties, and actual results will differ, perhaps materially, from those stated in the report. We cannot give any assurance that these assumptions will prove to be correct. If our actual results are materially less favorable than those shown in the Independent Engineer’s report, or if the assumptions in the Independent Engineer’s report on which we rely for certain of our financial estimates, prove to be incorrect, Sabine Pass LNG’s ability to pay distributions to us, and our ability to pay distributions to our unitholders, may be adversely affected.

Non-GAAP Financial Measure

Sabine Pass LNG’s EBITDA is computed as total revenues less non-cash deferred revenues, operating expenses, assumed commissioning costs and state and local taxes. It does not include depreciation expense and certain non-operating items. Because we have not forecasted such depreciation expense and non-operating items, we have not made any forecast of net income, which would be the most directly comparable financial measure under GAAP. As a result, we are unable to reconcile differences between forecasts of EBITDA and net income. EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as commercial banks, to assess:

 

    the anticipated financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

 

    the ability of our assets to generate cash sufficient to pay interest on our indebtedness; and

 

    our anticipated operating performance and return on invested capital compared to other comparable companies, without regard to their financing methods and capital structure.

Sabine Pass LNG’s EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Sabine Pass LNG’s EBITDA excludes some, but not all, items that affect net income and operating income, and these measures may vary among companies. Therefore, Sabine Pass LNG’s EBITDA may not be comparable to similarly titled measures of other companies.

 

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HOW WE MAKE CASH DISTRIBUTIONS

Operating Surplus and Capital Surplus

Overview

All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Definition of Available Cash

We define available cash in the partnership agreement, and it generally means, for each fiscal quarter, the sum of all cash and cash equivalents on hand at the end of the quarter, including cash released from the distribution reserve as available cash in accordance with our partnership agreement:

 

    less the amount of cash reserves established by our general partner to:

 

    provide for the proper conduct of our business;

 

    comply with applicable law, any of our debt instruments, or other agreements; and

 

    provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

 

    plus all additional cash and cash equivalents on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter and any amounts released from the distribution reserve as available cash in accordance with our partnership agreement. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement and in all cases are used solely for working capital purposes or to pay distributions to partners.

Definition of Operating Surplus

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

 

    $30 million (as described below); plus

 

    all of our cash receipts after the closing of this offering, excluding cash from:

 

    borrowings that are not working capital borrowings,

 

    sales of equity securities and debt securities,

 

    sales or other dispositions of assets outside the ordinary course of business,

 

    the termination of commodity hedge contracts or interest rate swap agreements prior to the termination date specified therein,

 

    capital contributions received, and

 

    corporate reorganizations or restructurings; plus

 

    working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for the quarter; plus

 

    all cash released from the distribution reserve; plus

 

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    cash distributions paid on equity issued in connection with the construction or development of a capital improvement or replacement asset during the period beginning on the date that we enter into a binding commitment to commence the construction or development of such capital improvement or replacement asset and ending on the earlier to occur of the date the capital improvement or replacement asset is placed into service and the date that it is abandoned or disposed of; less

 

    all of our operating expenditures (as defined below) after the closing of this offering; less

 

    the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

    all working capital borrowings not repaid within twelve months after having been incurred.

If a working capital borrowing, which increases operating surplus, is not repaid during the twelve month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $30 million of cash that we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus.

We define operating expenditures in the partnership agreement, and it generally means all of our expenditures, including, but not limited to, taxes, payments to our general partner, reimbursements of expenses incurred by our general partner on our behalf, non-pro rata repurchases of units, repayment of working capital borrowings, debt service payments, interest payments, payments made in the ordinary course of business under commodity hedge contracts and maintenance capital expenditures, provided that operating expenditures will not include:

 

    repayment of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus above when such repayment actually occurs;

 

    payments (including prepayments) of principal of and premium on indebtedness other than working capital borrowings;

 

    expansion capital expenditures;

 

    investment capital expenditures;

 

    payment of transaction expenses (including taxes) relating to interim capital transactions;

 

    distributions to our partners; and

 

    non-pro rata repurchases of units of any class made with the proceeds of a substantially concurrent equity issuance.

Where capital expenditures are made in part for expansion capital expenditures and in part for other purposes, our general partner, with the concurrence of the conflicts committee, will determine the allocation between the amounts paid for each.

Capital Expenditures

For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures required to maintain, including over the long-term, our asset base, and expansion capital expenditures are those capital expenditures that we expect will increase our asset base over the long-term.

 

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Maintenance capital expenditures include interest (and related fees) on debt incurred and distributions on equity issued to finance the construction or development of a replacement asset during the period from such financing until the earlier to occur of the date any such replacement asset is placed into service and the date that it is abandoned or disposed. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures or expansion capital expenditures.

Expansion capital expenditures are those capital expenditures that we expect will increase our asset base. Expansion capital expenditures include interest (and related fees) on debt incurred and distributions on equity issued to finance the construction or development of a capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement is placed into service and the date that it is abandoned or disposed.

As described above, none of investment capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because investment capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance the construction or development of a capital improvement or replacement asset during the period from such financing until the earlier to occur of the date any such capital improvement or replacement asset is placed into service or the date that it is abandoned or disposed, such interest payments and equity distributions are also not subtracted from operating surplus (except, in the case of maintenance capital expenditures, to the extent such interest payments and distributions are included in maintenance capital expenditures).

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes, but which is not expected to expand our asset base for more than the short-term.

Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by the board of directors of our general partner, based upon its good faith determination, subject to approval by our conflicts committee.

Definition of Capital Surplus

We also define capital surplus in the partnership agreement, and it will generally be generated only by:

 

    borrowings other than working capital borrowings;

 

    sales of debt and equity securities; and

 

    sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

Characterization of Cash Distributions

We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $30 million, cash receipts from our operations, cash released from our distribution reserve and cash from working capital borrowings. This amount does not reflect actual cash on hand at closing that is available for distribution to our unitholders. It is instead a provision that will enable us, if we choose, to distribute as operating surplus up to $30 million of cash that we

 

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receive in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Distribution Reserve

We will set aside $96.7 million as a distribution reserve to pay the $0.425 initial quarterly distribution per common unit for all common units and general partner units through the distribution made in respect of the quarter ending June 30, 2009. The distribution reserve will be restricted cash on our balance sheet and will be invested in short-term money market securities or U.S. treasuries. In the event that we issue additional common units prior to June 30, 2009, we will use a portion of the net proceeds from such issuance to increase the distribution reserve by an amount that our general partner, with the concurrence of the conflicts committee of its board of directors, determines is required to fund the initial quarterly distribution for such additional common units and related general partner units from their date of issuance through the distribution made in respect of the quarter ending June 30, 2009. Any amount remaining in the distribution reserve on August 15, 2009 will be distributed to Cheniere Holdings. We may distribute amounts in the distribution reserve to Cheniere Holdings prior to August 15, 2009 if our general partner, with the concurrence of its conflicts committee of its board of directors, determines that such reserves are not necessary to provide for distributions on all of our common units and general partner units for any quarter ending on or prior to June 30, 2009. If we generate cash from operations during the period from the closing of this offering to June 30, 2009, we will make quarterly distributions for our common units from such cash generated from operations and, if the amount of such cash is insufficient to make the full quarterly distribution, from amounts in the distribution reserve.

Subordination Period

General

During the subordination period, which will commence upon the closing of this offering, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the initial quarterly distribution of $0.425 per quarter, plus any arrearages in the payment of the initial quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Cheniere Holdings will own all of the 135,383,831 subordinated units, representing 83.7% of the limited partner interests in us. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until after the common units have received the initial quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordination period is to increase the likelihood that during this period there will be sufficient available cash to pay the initial quarterly distribution on the common units.

Definition of Subordination Period

The subordination period will end on the first to occur of the following dates:

 

    the first day after we have earned and paid at least the initial quarterly distribution on an annualized basis on each outstanding common unit and subordinated unit for any three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2010;

 

    the first day after we have earned and paid at least 150% of the initial quarterly distribution on each outstanding common unit and subordinated unit for each of any four consecutive quarters ending on or after March 31, 2008; and

 

    the date on which the general partner is removed as general partner of the partnership upon the requisite vote by holders of outstanding units under circumstances where cause does not exist and no units held by the general partner and its affiliates are voted in favor of such removal.

If the subordination period ends as a result of the removal of our general partner other than for cause where no units held by the general partner or its affiliates are voted in favor of such removal, in addition to each subordinated unit immediately converting into one common unit,

 

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

 

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    our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time.

Definition of Adjusted Operating Surplus

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

 

    operating surplus generated with respect to that period (other than amounts released from the distribution reserve); less

 

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

 

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

 

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

 

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

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. In addition, adjusted operating surplus does not include cash amounts held in the distribution reserve or amounts released therefrom to pay distributions.

Effect of Expiration of the Subordination Period

Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other units in distributions of available cash.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

    First, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the initial quarterly distribution for that quarter;

 

    Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the initial quarterly distribution on the common units for any prior quarters during the subordination period;

 

    Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the initial quarterly distribution for that quarter; and

 

    Thereafter, in the manner described in “—Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest, that we do not issue additional classes of equity securities and that the general partner is not removed without its consent.

Distributions of Available Cash from Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

    First, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the initial quarterly distribution for that quarter; and

 

    Thereafter, in the manner described in “—Incentive Distribution Rights” below.

 

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The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

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 that the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

If for any quarter:

 

    we have distributed available cash from operating surplus to the unitholders in an amount equal to the initial quarterly distribution; and

 

    we have distributed available cash from operating surplus on outstanding common units and the general partner interest in an amount necessary to eliminate any cumulative arrearages in payment of the initial quarterly distribution to the common units;

then we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

 

    First, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $0.489 per unit for that quarter (the “first target distribution”);

 

    Second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.531 per unit for that quarter (the “second target distribution”);

 

    Third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.638 per unit for that quarter (the “third target distribution”); and

 

    Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the initial quarterly distribution to the common unitholders. The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus that we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution,” until available cash from operating surplus that we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the initial quarterly distribution are also applicable to quarterly distribution amounts that are less than the initial quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume that our general partner maintains its 2% general partner interest and has not transferred its incentive distribution rights.

 

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Total Quarterly Distribution

   Marginal Percentage
Interest in Distributions
 
        Common and
Subordinated
Unitholders
    General
Partner
 
  

Target Amount

    

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 %

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

 

    First, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price;

 

    Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the initial quarterly distribution on the common units; and

 

    Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the initial quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the initial quarterly distribution, after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the initial quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the initial quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the unitholders, pro rata, and 50% to our general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume that our general partner maintains its 2% general partner interest and has not transferred its incentive distribution rights.

Adjustment to the Initial Quarterly Distribution and Target Distribution Levels

In addition to adjusting the initial quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

 

    the initial quarterly distribution;

 

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    the target distribution levels; and

 

    the unrecovered initial unit price.

For example, if a two-for-one split of the common and subordinated units should occur, the initial quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level. If we combine our common units into fewer units or subdivide our common units into a greater number of units, we will combine our subordinated units or subdivide our subordinated units, using the same ratio applied to the common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a court of competent jurisdiction so that we become taxable as a corporation or otherwise subjecting us to a material amount of entity level taxation for federal, state or local income tax purposes, we will reduce the initial quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (after deducting our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the initial quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the initial quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, although there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights currently owned by our general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

 

    First, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

 

    Second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of:

 

  (1)   the unrecovered initial unit price;

 

  (2)   the amount of the initial quarterly distribution for the quarter during which our liquidation occurs; and

 

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  (3)   any unpaid arrearages in payment of the initial quarterly distribution;

 

    Third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until the capital account for each subordinated unit is equal to the sum of:

 

  (1)   the unrecovered initial unit price; and

 

  (2)   the amount of the initial quarterly distribution for the quarter during which our liquidation occurs;

 

    Fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to:

 

  (1)   the sum of the excess of the first target distribution per unit over the initial quarterly distribution per unit for each quarter of our existence; less

 

  (2)   the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the initial quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;

 

    Fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to:

 

  (1)   the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

 

  (2)   the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence;

 

    Sixth, 75% to all unitholders, pro rata, and 25% to our general partner, until we allocate under this paragraph an amount per unit equal to:

 

  (1)   the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

 

  (2)   the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to our general partner for each quarter of our existence; and

 

    Thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

The percentages set forth above are based on the assumptions that our general partner maintains its 2% general partner interest and has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

 

    First, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

 

    Second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

 

    Thereafter, 100% to our general partner.

 

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The 2% interests set forth in the first and second bullet points above for our general partner are based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in our general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

 

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SELECTED FINANCIAL DATA OF OUR COMBINED PREDECESSOR ENTITIES

The following tables set forth the selected financial data of our predecessor entities on a combined basis for the periods and at the dates indicated. Our combined predecessor entities refers to Sabine Pass LNG and its limited partner and general partner.

The combined statement of operations data for the period from October 20, 2003 (inception) through December 31, 2003, for the years ended December 31, 2004 and 2005, and the combined balance sheet information at December 31, 2004 and 2005 are derived from our audited combined financial statements, which are included elsewhere in this prospectus. The summary combined balance sheet information at December 31, 2003 has been derived from our audited combined balance sheet as of December 31, 2003, which is not included in this prospectus. We have derived the combined statement of operations data for the nine months ended September 30, 2005 and 2006 and for the period from October 20, 2003 (inception) to September 30, 2006, and the combined balance sheet data at September 30, 2006 from our unaudited combined financial statements, which are included elsewhere in this prospectus. The unaudited combined financial statements have been prepared on the same basis as the audited combined financial statements and, in the opinion of management of our general partner, include all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation of the information set forth therein. Our past financial or operating performance is not a reliable indicator of our future performance (particularly anticipated revenues, debt costs and expenses), and you should not use our historical performance to anticipate results or future period trends.

We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the combined financial statements and the accompanying notes included in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

    Combined Predecessor Entities  
   

Period from
October 20,
2003
(inception) to
December 31,

2003

   

Year ended

December 31,

   

Nine months ended

September 30,

   

Period from
October 20,
2003
(inception) to
September 30,

2006

 
      2004     2005     2005     2006    
    (in thousands)  
                      (unaudited)     (unaudited)     (unaudited)  

Statement of Operations Data:

           

Revenues

  $ —       $ —       $ —       $ —       $ —       $ —    

Expenses

    2,763       4,682       4,718       3,410       9,399       21,563  
                                               

Loss from operations

    (2,763 )     (4,682 )     (4,718 )     (3,410 )     (9,399 )     (21,563 )

Other income

    —         28       456       83       112       597  
                                               

Net loss

  $ (2,763 )   $ (4,654 )   $ (4,262 )   $ (3,327 )   $ (9,287 )   $ (20,966 )
                                               

Cash Flow Data:

           

Cash flows provided by (used in) operating activities

  $ 101     $ 23,192     $ 6,320     $ 3,204     $ (6,231 )   $ 23,382  

Cash flows used in investing activities

    (101 )     (124 )     (246,337 )     (180,998 )     (296,383 )     542,944  

Cash flows provided by (used in) financing activities

    —         (1,246 )     218,200       156,002       302,621       519,575  

 

    Combined Predecessor Entities
    December 31,  

September 30,

2006

    2003   2004   2005  
    (in thousands)
                (unaudited)

Balance Sheet Data (at period end):

       

Cash and cash equivalents (unrestricted)

  $ —     $ 21,822   $ 5   $ 7

Property, plant and equipment

    96     212     270,740     563,988

Total assets

    101     23,316     309,139     613,832

Long-term debt(1)

    —       —       72,485     386,730

Deferred revenues

    —       22,000     40,000     40,000

Total other long-term liabilities

    2,864     17,418     120     19,927

(1)   In November 2006, Sabine Pass LNG issued $2,032 million of senior secured notes due 2013 and 2016 and repaid all outstanding debt incurred under an amended and restated credit facility; $886.7 million of the net proceeds received from the issuance of the Sabine Pass LNG notes was deposited in a restricted construction account.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The combined financial statements included in this prospectus reflect the combined business and financial results of Sabine Pass LNG and its general partner and limited partner to be contributed to us by Cheniere in connection with this offering. The following discussion analyzes the financial condition and results of operations of these combined predecessor entities. You should read the following discussion of the financial condition and results of operations for these combined predecessor entities in conjunction with the historical combined financial statements and notes included elsewhere in this prospectus.

In addition to historical information, the following discussion contains forward-looking statements that are subject to significant risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including the factors set forth under the captions “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” and elsewhere in this prospectus.

Overview

We are a Delaware limited partnership recently formed by Cheniere to develop, own and operate the Sabine Pass LNG receiving terminal currently under construction in western Cameron Parish, Louisiana on the Sabine Pass Channel. The Sabine Pass LNG receiving terminal is being constructed in two phases:

 

    Phase 1.    The initial phase of the Sabine Pass LNG receiving terminal was designed with an initial regasification capacity of 2.6 Bcf/d and three LNG storage tanks with an aggregate LNG storage capacity of 10.1 Bcf, along with two unloading docks capable of handling the largest LNG carriers currently being built. Construction of Phase 1 began in March 2005, commercial operation is expected to commence during the second quarter of 2008 and construction is expected to be completed during the third quarter of 2008. We estimate the cost to construct Phase 1 of the Sabine Pass LNG receiving terminal will be approximately $900 million to $950 million, before financing costs. As of October 31, 2006, Sabine Pass LNG had paid $531.1 million of Phase 1 construction costs.

 

    Phase 2.    The first stage of the second phase of the development of the Sabine Pass LNG receiving terminal is expected to increase the regasification capacity from 2.6 Bcf/d to 4.0 Bcf/d by adding two LNG storage tanks, additional vaporizers and related facilities. We estimate the cost to construct Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal will be approximately $500 million to $550 million, before financing costs. As of October 31, 2006, Sabine Pass LNG had paid $46.3 million of Phase 2 – Stage 1 construction costs.

We are a development stage company without any revenues, operating cash flows or operating history. We currently do not expect that we will begin receiving any revenues from operations until the second quarter of 2008, at the earliest.

Our Contracted Capacity

Upon completion of construction, the Sabine Pass LNG receiving terminal will have approximately 4.0 Bcf/d of regasification capacity and approximately 16.8 Bcf of storage capacity. All of this capacity has been contracted for under three 20-year, firm commitment terminal use agreements, or TUAs. Each customer must make payments on a “take-or-pay” basis, which means that the customer will be obligated to pay the full contracted amount of monthly fees whether or not it uses any of its reserved capacity. Provided the Sabine Pass LNG receiving terminal has achieved commercial operation at 2.0 Bcf/d, which we expect will occur in April 2008, these “take-or-pay” TUA payments will be made as follows:

 

    Total has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly payments to us aggregating approximately $125 million per year for 20 years commencing April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion.

 

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    Chevron has reserved approximately 1.0 Bcf/d of regasification capacity and has agreed to make monthly payments to us aggregating approximately $125 million per year for 20 years commencing not later than July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

 

    Cheniere Marketing has reserved approximately 2.0 Bcf/d of regasification capacity, is entitled to use any capacity not utilized by Total and Chevron and has agreed to make monthly payments to us aggregating approximately $250 million per year for at least 19 years commencing January 1, 2009, plus payments of $5 million per month during an initial commercial operations ramp-up period in 2008. Cheniere has guaranteed Cheniere Marketing’s obligations under its TUA.

Each of Total and Chevron has paid us $20 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 fees payable under its TUA.

Liquidity and Capital Resources

General

We estimate that the aggregate total cost to complete construction of Phase 1 and Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal will be approximately $1.4 billion to $1.5 billion, before financing costs. Our cost estimates are subject to change due to such items as cost overruns, change orders, increased component and material costs, escalation of labor costs and increased spending to maintain our construction schedule.

We will fund our construction period capital resource requirements from a portion of the $2,032 million in net proceeds received from Sabine Pass LNG’s issuance of senior secured notes in November 2006. We placed $335 million of the net proceeds in a reserve account to fund scheduled interest payments on the Sabine Pass LNG notes through May 2009. We also placed approximately $887 million in a construction account, which, until satisfaction of construction completion milestones, will only be applied to pay construction and startup costs of the Sabine Pass LNG receiving terminal and to pay other expenses incidental for us to complete construction of the project. We used the remaining net proceeds received from the issuance of the Sabine Pass LNG notes to repay indebtedness, to make a distribution to Cheniere Holdings for the repayment of its outstanding term loan and to pay fees and expenses related to the issuance of the Sabine Pass LNG notes.

We believe that we have adequate financial resources to complete Phase 1 and Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal and to meet our anticipated operating, maintenance and debt service requirements and all of the initial quarterly distribution on the common units through the first half of 2009. Furthermore, we anticipate that:

 

    cash flows from operations will commence in the second quarter of 2008, when Phase 1 of the Sabine Pass LNG receiving terminal is anticipated to commence commercial operation; and

 

    beginning in the third quarter of 2009, cash flows from operations will be sufficient to cover all debt service on the Sabine Pass LNG notes, all other costs of operating Sabine Pass LNG and all of the initial quarterly distribution on the common units, subordinated units and general partner units.

Any delays in construction could prevent us from commencing operations when we anticipate and could prevent us from realizing anticipated cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to our incurrence of construction costs and other outflows and by the timing of our receipt of cash flows under the TUAs in relation to our incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between our liquidity sources and cash needs, including factors such as construction delays and breaches of construction agreements. After the construction period, our business may not generate sufficient cash flow from operations, currently anticipated costs may increase or future borrowings may not be available to us in amounts sufficient to enable us to

 

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pay our indebtedness or to fund our other liquidity needs, including operating expenses and distributions to our unitholders. The operation of our business is subject to many risks (many of which are beyond our control), including general economic, financial, competitive, legislative, regulatory and other developments.

Uses of Capital

Phase 1 EPC Agreement

In December 2004, Sabine Pass LNG entered into a lump-sum turnkey EPC agreement with Bechtel for Phase 1 of the Sabine Pass LNG receiving terminal. Except for certain third-party work specified in the EPC

agreement, the work to be performed by Bechtel includes all of the work required to achieve substantial completion and final completion of Phase 1 of the Sabine Pass LNG receiving terminal in accordance with the requirements of the EPC agreement.

Pursuant to the EPC agreement, Sabine Pass LNG agreed to pay Bechtel a contract price of $646.9 million plus certain reimbursable costs for the work performed under the EPC agreement. This contract price is subject to adjustment for certain costs of materials, contingencies, change orders and other items. As of December 19, 2006, change orders for $105.7 million were approved, primarily for design changes, increases in costs of materials, insurance costs and costs related to the 2005 hurricanes, increasing the total contract price to $752.6 million.

Phase 2 Construction Agreements

In July 2006, Sabine Pass LNG entered into three construction agreements to facilitate construction of the Phase 2 – Stage 1 expansion, as follows:

 

    EPCM agreement.    Sabine Pass LNG entered into an EPCM agreement with Bechtel pursuant to which Bechtel will provide: design and engineering services for Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal project, except for such portions to be designed by other contractors and suppliers that Sabine Pass LNG contracts with directly; construction management services to manage the construction of the LNG receiving terminal; and a portion of the construction services. Under the terms of the EPCM agreement, Bechtel will be paid on a cost reimbursable basis, plus a fixed fee in the amount of $18.5 million. A discretionary bonus may be paid to Bechtel at Sabine Pass LNG’s sole discretion upon completion of Phase 2 – Stage 1. For more information, please read “Description of Principal Construction Agreements—Phase 2 – Stage 1 EPCM Agreement.”

 

    EPC Tank Contract.    Sabine Pass LNG entered into an EPC LNG tank contract, or tank contract, with Zachry Construction Corporation, or Zachry, and Diamond LNG LLC, or Diamond, under which Zachry and Diamond will furnish all plant, labor, materials, tools, supplies, equipment, transportation, supervision, technical, professional and other services, and perform all operations necessary and required to satisfactorily engineer, procure materials for and construct the two Phase 2 – Stage 1 LNG storage tanks. In addition, Sabine Pass LNG has the option (to be elected on or before March 31, 2007) for Zachry and Diamond to engineer, procure and construct a sixth LNG storage tank, with the cost and completion date to be agreed upon if the option is exercised. The tank contract provides that Zachry and Diamond will receive a lump-sum, total fixed price payment for the two Phase 2 – Stage 1 tanks of approximately $140.9 million, which is subject to adjustment based on fluctuations in the cost of labor and certain materials, including the steel used in the Phase 2 – Stage 1 tanks, and change orders. For more information, please read “Description of Principal Construction Agreements—Phase 2 – Stage 1 EPC LNG Tank Contract.”

 

   

EPC LNG Unit Rate Soil Contract.    Sabine Pass LNG entered into an EPC LNG unit rate soil contract, or soil contract, with Remedial Construction Services, L.P., or Recon. Under the soil contract, Recon is required to furnish all plant, labor, materials, tools, supplies, equipment, transportation, supervision, technical, professional and other services, and perform all operations necessary and required to satisfactorily conduct soil remediation and improvement on the Phase 2 site, unless

 

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otherwise set forth in the soil contract. Upon issuing a final notice to proceed in August 2006, Sabine Pass LNG paid Recon an initial payment of approximately $2.9 million. The soil contract price is based on unit rates. Payments under the soil contract will be made based on quantities of work performed at unit rates. For more information, please read “Description of Principal Construction Agreements—Phase 2 – Stage 1 EPC LNG Soil Contract.”

Cheniere Marketing’s Option for a Sixth LNG Storage Tank

The Cheniere Marketing TUA provides that, at Cheniere Marketing’s request, Sabine Pass LNG must construct a sixth LNG storage tank with a working capacity of approximately 160,000 cubic meters of LNG as soon as possible but not later than four years after notification from Cheniere Marketing. Our obligation to construct the additional LNG storage tank will be subject to receipt of all FERC and other required governmental permits and approvals and obtaining financing that we consider reasonably acceptable in form and content.

If Cheniere Marketing exercises its option to require us to construct the sixth LNG storage tank, we may have to incur additional debt. Our internal estimate of the cost to construct the sixth tank is in the range of $120 million to $140 million. As described above, we have an option, exercisable on or before March 31, 2007, to require Zachry and Diamond to engineer, procure and construct the sixth LNG storage tank, with the cost and completion date to be agreed upon if the option is exercised. If Cheniere Marketing exercises its option after March 31, 2007, we may have to negotiate one or more new construction agreements with one or more new contractors. Sabine Pass LNG will not receive additional revenues in exchange for constructing a sixth LNG storage tank under the Cheniere Marketing TUA.

Cash Distributions to Unitholders

For each calendar quarter through June 30, 2009, we will make quarterly cash distributions of $0.425 per unit on all outstanding common units and general partner units, using cash from a $96.7 million distribution reserve that will be funded with proceeds from this offering. We believe that the amount of the distribution reserve, together with interest expected to be earned on that amount and cash from operations, if any, , will be sufficient to allow us to pay the full initial quarterly distribution on all our outstanding common units, as well as related distributions to our general partner, for each quarter through June 30, 2009. After the quarter ended June 30, 2009, we intend to pay distributions to our unitholders primarily with operating cash flows.

Services Agreements

Operation and Maintenance Agreement.    In February 2005, Sabine Pass LNG entered into an Operation and Maintenance Agreement, or O&M Agreement, with Cheniere LNG O&M Services, L.P., or O&M Services, an indirect wholly-owned subsidiary of Cheniere. Pursuant to the O&M Agreement, O&M Services agreed to provide all necessary services required to construct, operate and maintain the Sabine Pass LNG receiving terminal. The O&M Agreement will remain in effect until 20 years after substantial completion of the facility. Prior to substantial completion of the facility, Sabine Pass LNG is required to pay a fixed monthly fee of $95,000 (indexed for inflation). The fixed monthly fee will increase to $130,000 (indexed for inflation) upon substantial completion of the facility, and O&M Services will thereafter be 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 O&M Services at the beginning of each operating year. In addition, Sabine Pass LNG is required to reimburse O&M Services for its maintenance capital expenditures and operating expenses, which are comprised of labor, maintenance, land lease and insurance expenses.

At or near the closing of this offering, O&M Services will assign the O&M Agreement to our general partner, and O&M Services and our general partner will enter into a services and secondment agreement pursuant to which we anticipate that certain employees of O&M Services will be seconded to our general partner to provide operating and routine maintenance services with respect to the Sabine Pass LNG receiving terminal

 

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under the direction, supervision and control of our general partner. Under this agreement, our general partner will pay O&M Services amounts that it receives from Sabine Pass LNG under the O&M Agreement.

Management Services Agreements.    In February 2005, Sabine Pass LNG entered into a Management Services Agreement, or the Sabine Pass LNG MSA, with its general partner, Sabine Pass LNG–GP, Inc., which is a wholly-owned subsidiary of us. Pursuant to the Sabine Pass LNG MSA, Sabine Pass LNG appointed its general partner to manage the construction and operation of the Sabine Pass LNG receiving terminal, excluding those matters provided for under the O&M Agreement. The Sabine Pass LNG MSA terminates 20 years after the commercial start date set forth in the Total TUA. Prior to substantial completion of construction of the Sabine Pass LNG receiving terminal, Sabine Pass LNG is required to pay its general partner a monthly fixed fee of $340,000 (indexed for inflation); thereafter, the monthly fixed fee will increase to $520,000 (indexed for inflation).

In September 2006, the general partner of Sabine Pass LNG entered into a Management Services Agreement with Cheniere LNG Terminals, Inc., or Cheniere Terminals, a wholly-owned subsidiary of Cheniere. Pursuant to this agreement, Cheniere Terminals provides the general partner with technical, financial, staffing and related support necessary to allow it to meet its obligations to Sabine Pass LNG under the Sabine Pass LNG MSA. Under this agreement with Cheniere Terminals, the general partner of Sabine Pass LNG pays Cheniere Terminals amounts that it receives from Sabine Pass LNG for management of the Sabine Pass LNG receiving terminal.

Services Agreement.    Our general partner anticipates entering into a services agreement with Cheniere Terminals upon the closing of this offering. Under this agreement, we will pay Cheniere Terminals an annual administrative fee of $10 million (adjusted for inflation after January 1, 2007) commencing in the first quarter of 2009 for the provision of various general and administrative services for our benefit and 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. The annual administrative fee includes expenses incurred by Cheniere Terminals to perform all technical, financial, accounting, treasury, tax, staffing and related support and all management and other services necessary or reasonably requested on behalf of our partnership by our general partner in order to conduct our business as contemplated by our partnership agreement. The fee does not include reimbursements for direct expenses that Cheniere Terminals 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.

For more information on these agreements, please read “Certain Relationships and Related Transactions.”

Public Company Expenses

Following this offering, our general and administrative expenses will increase as a result of becoming a publicly traded partnership. In addition, Sabine Pass LNG will also become a reporting entity under the Exchange Act once its registration statement relating to the Sabine Pass LNG notes is declared effective. As a result, we anticipate that our combined total annual general and administrative expenses following the completion of this offering will increase by approximately $2.5 million. This increase is expected to result from the cost of additional accounting and support services to be incurred after this offering, including costs related to compliance with the Sarbanes-Oxley Act of 2002, filing annual and quarterly reports with the SEC, increased audit fees, tax compliance and publicly traded partnership tax reporting, investor relations, director compensation, directors’ and officers’ insurance, legal fees, registrar and transfer agent fees and stock exchange fees. Cheniere will advance us funds to pay public company expenses associated with being a publicly traded partnership through 2008, after which time we will use available cash to pay such expenses directly and, after payment of the initial quarterly distribution on all units, to reimburse Cheniere.

 

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Maintenance Capital Expenditures

Beginning in 2009, Sabine Pass LNG expects to incur approximately $1.5 million per year in maintenance capital expenditures, which are generally capital expenditures to maintain the operating capacity of the Sabine Pass LNG receiving terminal and extend its useful life.

State Tax Sharing Agreement

In November 2006, Sabine Pass LNG entered into a state tax sharing agreement with Cheniere. 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. The agreement is effective for tax returns first due on or after January 1, 2008. For more information on this agreement, please read “Certain Relationships and Related Transactions—Arrangement Regarding Taxes.”

Debt Agreements

Sabine Pass LNG Notes

In November 2006, Sabine Pass LNG issued $550 million aggregate principal amount of 7.25% Senior Secured Notes due 2013 and $1,482 million aggregate principal amount of 7.50% Senior Secured Notes due 2016 in a private placement. Please read “Indebtedness.”

Amended Sabine Pass Credit Facility

In February 2005, Sabine Pass LNG entered into an $822 million credit agreement with HSBC Bank, USA and Société Générale and a syndicate of financial institutions, and related interest rate swap agreements with HSBC Bank, USA and Société Générale. This original credit facility was subsequently amended and restated in July 2006. The amended credit facility increased the amount of loans available to Sabine Pass LNG from $822 million under the original credit facility to $1.5 billion to finance Phase 1 and Phase 2 – Stage 1 expansion construction of the Sabine Pass LNG receiving terminal. In connection with the closing of the credit facility and subsequent amendment, Sabine Pass LNG entered into interest rate swap agreements with HSBC Bank, USA and Société Générale. In connection with the issuance of the notes in November 2006, the amended credit facility and related interest rate swaps were paid in full and terminated.

Historical Cash Flows

Net cash used in operating activities was $6.2 million during the nine months ended September 30, 2006 compared to $3.2 million net cash provided by operating activities in the same period of 2005. Net cash provided by operating activities during the nine months ended September 30, 2005 was primarily the result of our receipt of $15.0 million in advance terminal capacity reservation fees partially offset by a $7.4 million reimbursement of expenses paid to an affiliate. Absent these items, we would have recorded net cash used in operating activities of $4.4 million for the nine-month period ended September 30, 2005.

Net cash used in investing activities was $296.4 million during the nine months ended September 30, 2006 compared to net cash used in investing activities of $181.0 million during the nine months ended September 30, 2005. During the first nine months of 2006, we invested $287.5 million of cash in expenditures relating to the construction of the Sabine Pass LNG receiving terminal compared to $164.5 million in the comparable period of 2005. In addition, we advanced $4.9 million to third-party contractors for the procurement of long-term assets. Investment activities during the first nine months of 2005 included $16.2 million of advances to Bechtel, net of transfers to construction-in-progress.

 

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Net cash provided by financing activities during the first nine months of 2006 was $302.6 million compared to net cash provided by financing activities of $156.0 million during the same period of 2005. During the first nine months of 2006, we received proceeds from borrowings under the original Sabine Pass LNG credit facility totaling $351.5 million. These proceeds were partially offset by $11.5 million in debt issuance costs primarily related to the amended Sabine Pass LNG credit facility, and the repayment of a $37.4 million related party subordinated note. During the first nine months of 2005, we received $171.8 million in limited partner capital contributions from an affiliate, which was partially reduced by $15.8 million in debt issuance costs related to the original Sabine Pass LNG credit facility.

Our unrestricted cash and cash equivalent ending balance was $7,000 as of September 30, 2006.

Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2005 (in thousands).

 

     Payments Due for Years Ending December 31,(1)(2)
     Total    2006    2007-2008    2009-2010    Thereafter

Operating site leases

   $ 43,529    $ 1,501    $ 3,002    $ 3,002    $ 36,024

(1)   As of September 30, 2006, we had $351.5 million outstanding under the Sabine Pass LNG amended credit facility, which was repaid in November 2006 concurrently with a portion of the net proceeds from the issuance of the Sabine Pass LNG notes.
(2)   On November 9, 2006, Sabine Pass LNG issued $550 million of senior secured notes due 2013 and $1,482 million of senior secured notes due 2016.

Lease Commitments and Other Obligations

In January 2005, Sabine Pass LNG exercised options and entered into three land leases for the Sabine Pass LNG receiving terminal site. The leases have an initial term of 30 years, with options to renew for six 10-year extensions. In February 2005, two of the three leases were amended, thereby increasing the total acreage under lease to 853 acres and increasing the annual lease payments to $1.5 million. For 2005, these payments were capitalized as part of the construction cost of the Sabine Pass LNG receiving terminal; however, beginning in January 2006, these lease payments have been expensed as required by Financial Accounting Standards Board, or FASB, Staff Position, or FSP, 13-1, Accounting for Rental Costs Incurred During Construction.

Inflation

We have experienced escalating steel prices relating to the construction of the Sabine Pass LNG receiving terminal and increasing labor costs in connection with the collateral effects of the 2005 hurricanes, which we believe have been fully reflected in our estimated costs to construct the Sabine Pass LNG receiving terminal.

Off-Balance Sheet Arrangements

As of September 30, 2006, we had no off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed the debt of any other party.

 

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Results of Operations

Nine Months Ended September 30, 2006 compared to Nine Months Ended September 30, 2005

Overview

Our financial results for the nine months ended September 30, 2006 reflected a net loss of $9.3 million compared to a net loss of $3.3 million for the same period in 2005. Because we are a development stage company and our operations consist solely of constructing the Sabine Pass LNG receiving terminal, we have not generated any operating revenues.

Expenses

Total expenses were $9.4 million during the first nine months of 2006 compared to $3.4 million during the first nine months of 2005, a $6.0 million increase. This increase was primarily attributable to the reimbursement of development expenses related to Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal and land site rental costs.

Prior to the execution of the amended Sabine Pass LNG credit facility in July 2006, an affiliate spent $4.5 million related to technical, consulting, legal and other professional fees associated with front-end engineering and design work, obtaining an order from the FERC authorizing construction of Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal and other required permitting. Concurrently with the execution of the amended Sabine Pass LNG credit facility in July 2006, these expenses became our obligation, and we reimbursed the affiliate for the expenses in August 2006. During 2005, land site rental payments were capitalized as part of the construction cost of the Sabine Pass LNG receiving terminal; however, beginning in January 2006, these rental payments ($1.1 million) have been expensed as required by FAS No. 13-1, Accounting for Rental Costs Incurred during a Construction Period.

Fiscal Year Ended December 31, 2005 compared to Fiscal Year Ended December 31, 2004

Overview

Our financial results for the year ended December 31, 2005 reflected a net loss of $4.3 million compared to a net loss of $4.7 million for the year ended December 31, 2004.

Expenses

Total expenses for each of the years ended December 31, 2004 and 2005 were $4.7 million. During 2004, primarily all of our expenses related to technical, consulting, legal and other professional fees associated with front-end engineering and design work, obtaining an order from FERC authorizing construction of the Sabine Pass LNG receiving terminal and other required permitting. In March 2005, we received the order from FERC authorizing construction of the Sabine Pass LNG receiving terminal and, accordingly, began construction. In mid-February 2005, we began paying overhead charges to affiliates related to services required to construct the Sabine Pass LNG receiving terminal. These charges totaled $4.1 million in 2005 (net of $0.3 million capitalized).

Other Income

Other income for the year ended December 31, 2005 was $0.5 million compared to a negligible amount for 2004. We recorded a derivative gain of $0.3 million in 2005 compared to none in 2004. The derivative gain was related to the ineffective portion of our interest rate swap gain associated with the original Sabine Pass LNG credit facility entered into in February 2005.

Period from October 20, 2003 (Inception) to December 31, 2003

We recorded a net loss of $2.8 million for the period from October 20, 2003 (inception) to December 31, 2003. The net loss related to expenses incurred for technical, consulting, legal and other professional fees associated with front-end engineering and design work, obtaining an order from FERC authorizing construction of the Sabine Pass LNG receiving terminal and other required permitting.

 

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Other Matters

Critical Accounting Estimates and 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 the specific set of circumstances existing in our business. We make every effort 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. Beginning in 2006, site rental costs are expensed as required by FSP 13-1, Accounting for Rental Costs Incurred During a Construction Period.

During the construction period of the Sabine Pass LNG receiving terminal, we capitalize interest and other related debt costs in accordance with Statement of Financial Accounting Standards, or SFAS, No. 34, Capitalization of Interest Cost, as amended by SFAS No. 58, Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method (an Amendment of FASB Statement No. 34). Upon commencement of operations, capitalized interest, as a component of the total cost, will be amortized over the estimated useful life of the asset.

Revenue Recognition

LNG receiving terminal capacity reservation fees are recognized as revenue over the term of the respective TUAs. Advance capacity reservation fees are deferred initially.

Cash Flow Hedges

As defined in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, cash flow hedge transactions hedge the exposure to variability in expected future cash flows (i.e., in our case, the variability of floating interest rate exposure). In the case of cash flow hedges, the hedged item (the underlying risk) is generally unrecognized (i.e., not recorded on the 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, SFAS No. 133 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. Any ineffective portion will be reflected in earnings.

New Accounting Pronouncements

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. SFAS No. 155 provides entities with relief from having to separately determine the fair value of an embedded derivative that would otherwise be required to be bifurcated from its host contract in accordance with SFAS No. 133. SFAS No. 155 allows an entity to make an irrevocable election to measure such a hybrid financial

 

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instrument at fair value in its entirety, with changes in fair value recognized in earnings. SFAS No. 155 is effective for all financial instruments acquired, issued or subject to a remeasurement event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We believe that the adoption of SFAS No. 155 will not have a material impact on our financial position, results of operations or cash flows.

In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of Financial Assets – An Amendment to FASB Statement No. 140. SFAS No. 156 requires entities to recognize a servicing asset or liability each time they undertake an obligation to service a financial asset by entering into a servicing contract in certain situations. This statement also requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value and permits a choice of either the amortization or fair value measurement method for subsequent measurement. The effective date of this statement is for annual periods beginning after September 15, 2006, with earlier adoption permitted as of the beginning of an entity’s fiscal year provided the entity has not issued any financial statements for that year. We do not plan to adopt SFAS No. 156 early, and we are currently assessing the impact on our combined financial statements.

In July 2006, the FASB issued FASB Interpretation, or FIN, No. 48, Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109. FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The provisions of FIN No. 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN No. 48. The cumulative effect of applying the provisions of FIN No. 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. The provisions of FIN No. 48 are effective for fiscal years beginning after December 15, 2006. Earlier application is permitted as long as the enterprise has not yet issued financial statements, including interim financial statements, in the period of adoption. We believe that the adoption of FIN No. 48 will not have a material impact on our financial position, results of operations or cash flows.

In July 2006, the FASB issued FSP No. FAS 13-2, Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction. FSP No. FAS 13-2 requires that changes in the projected timing of income tax cash flows generated by a leveraged lease transaction be recognized as a gain or loss in the year in which change occurs. The pretax gain or loss is required to be included in the same line item in which the leveraged lease income is recognized, with the tax effect being included in the provision for income taxes. FSP No. FAS 13-2 is effective for fiscal years beginning after December 15, 2006. We believe that the adoption of FSP No. FAS 13-2 will not have a material impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. We are currently determining the effect, if any, the adoption of SFAS No. 157 will have on our financial statements.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plan—an amendment of FASB Statement No. 87, 88, 106 and 132(R). SFAS No. 158 requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and recognize changes in the funded status in the year

 

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in which the changes occur. SFAS No. 158 is effective for fiscal years ending after December 15, 2006. We believe that the adoption of SFAS No. 158 will not have a material impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued FSP No. AUG AIR-1, Accounting for Planned Major Maintenance Activities. FSP No. AUG AIR-1 prohibits the use of the accrue-in-advance method for accounting for major maintenance activities and confirms the acceptable methods of accounting for planned major maintenance activities. FSP No. AUG AIR-1 is effective the first fiscal year beginning after December 15, 2006. We believe that the adoption of FSP No. AUG AIR-1 will not have a material impact on our financial position, results of operations or cash flows.

Quantitative and Qualitative Disclosures About Market Risk

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 balance sheet.

Interest Rates

Prior to termination of the amended Sabine Pass LNG credit facility on November 9, 2006, we were exposed to changes in interest rates primarily as a result of our debt obligations. The fair value of our fixed rate debt was affected by changes in market rates. We utilized interest rate swap agreements to mitigate exposure to rising interest rates. We did not use interest rate swap agreements for speculative or trading purposes.

At September 30, 2006, we had approximately $351.5 million of non-affiliated debt outstanding. The amended Sabine Pass LNG credit facility bore interest at floating rates; however, Sabine Pass LNG entered into interest rate swaps with respect to this loan amount. In connection with the issuance of the Sabine Pass LNG notes, the amended Sabine Pass LNG credit facility and interest rate swaps were terminated. The following table summarizes the fair market values of our interest rate swap agreements as of September 30, 2006 (in thousands):

 

Maturity Date

   Weighted
Average
Notional
Principal
Amount
  

Fixed Interest
Rate (Pay)

  

Weighted Average

Interest Rate

   Fair Market
Value(1)
 

September through December 2006

   $ 468,847    4.49% - 5.69%    US $        LIBOR BBA    $ 917  

January through December 2007

     768,989    4.49% - 5.69%    US $        LIBOR BBA      1,230  

January through December 2008

     1,075,088    4.49% - 5.69%    US $        LIBOR BBA      (1,212 )

January through December 2009

     1,243,482    4.49% - 5.69%    US $        LIBOR BBA      (2,273 )

January through December 2010

     1,249,997    4.98% - 5.69%    US $        LIBOR BBA      (3,359 )

January through December 2011

     1,249,996    4.98% - 5.69%    US $        LIBOR BBA      (1,943 )

January through December 2012

     1,250,000    4.98% - 5.69%    US $        LIBOR BBA      (3,210 )

January through December 2013

     881,483    5.69%    US $        LIBOR BBA      (3,742 )

January through December 2014

     619,241    5.69%    US $        LIBOR BBA      (1,831 )

January through June 2015

     597,166    5.69%    US $        LIBOR BBA      (1,406 )
                 
            $ (16,829 )
                 

(1)   The fair market value is based upon a marked-to-market calculation utilizing an extrapolation of third-party mid-market LIBOR rate quotes at September 30, 2006.

In connection with the termination of the amended Sabine Pass LNG credit facility in November 2006, Sabine Pass LNG closed out its interest rate swap positions. The early settlement of these positions resulted in a $20.5 million loss.

 

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INDUSTRY

We obtained the information in this prospectus about the LNG industry from several independent outside sources, including: the Energy Information Administration, or EIA, an independent statistical and analytical agency within the U.S. Department of Energy; Groupe International des Importateurs de Gaz Naturel Liquéfié, or GIIGNL, an industry organization representing LNG importers; the BP Statistical Review of World Energy, June 2006; and the FERC. Much of the most recent government data available regarding the LNG industry is for 2004 and 2005. Although we believe that these independent sources are reliable as of their respective dates, the information contained in them has not been independently verified. As a result, you should be aware that the market and industry data contained in this prospectus, and beliefs and estimates based on such data, may not be reliable.

Overview

LNG is an effective means to transport natural gas from remote areas to demand centers.    In 2005, natural gas satisfied more than 23% of worldwide, and 25% of North American, primary energy consumption according to the 2006 BP Statistical Review. The EIA expects global demand for natural gas to grow by 2.4% per year, on average, from 2003 to 2030. Natural gas has an advantage over other primary energy sources such as oil and coal because it is a clean burning fuel and, therefore, more environmentally friendly. Substantial natural gas reserves are located in countries that have low energy consumption and are far from major energy demand centers. Natural gas supplies close to some major consuming markets are facing declining production. To transport natural gas effectively from remote locations to major energy demand centers, natural gas is liquefied to condense its volume and permit efficient transportation by sea. Liquefying natural gas is, therefore, becoming an increasingly significant alternative for distributing natural gas produced in remote areas to key centers of natural gas consumption.

Global LNG export capability is expanding.    The EIA reports that between 1995 and 2005, annual LNG exports increased by an 8% compound annual growth rate, from 9 Bcf/d to 19 Bcf/d, as a result of increasing worldwide energy demand and achievement of economies of scale in liquefaction, shipping and regasification. Historically, the LNG trade was led by large utilities in Europe, Japan, South Korea and Taiwan, which lack adequate indigenous supplies of natural gas. LNG export facilities in Algeria, Indonesia, Malaysia, Australia and Alaska served these markets. Today, European utilities seek to diversify their supply sources to meet peak winter demand, and North American producers seek to support growing demand. This has encouraged more liquefaction development globally, including in the Americas (Trinidad, Venezuela and Peru), Africa (Egypt, Algeria, Nigeria, Equatorial Guinea, Angola and Libya), the Middle East (Qatar, Oman and Iran), Asia (Indonesia, Malaysia and Papua New Guinea), Australia and Russia.

North America, the largest natural gas market in the world, needs new natural gas supplies, including LNG.    North America has the largest interconnected natural gas market in the world, consuming approximately 76 Bcf/d in 2004, according to the EIA. LNG’s contribution to the North American market has historically been minimal, due mainly to abundant, indigenous supplies of low cost natural gas. The average wellhead price of natural gas produced in the United States has increased significantly from 2002 to 2006. The former Chairman of the Federal Reserve, Alan Greenspan, stated in May 2003 in testimony before Congress that greater access to global natural gas reserves is required for North American natural gas markets “to be able to adjust effectively to unexpected shortfalls in domestic supply [and that] access to world natural gas supplies will require a major expansion of LNG terminal import capacity.” Ben Bernanke, the current Federal Reserve Chairman, reaffirmed this view in February 2006, when he said, “building LNG terminals is one thing that we can do and we should continue to do to create a more global market for natural gas.”

North America’s LNG receiving capability is expanding, and LNG’s share of the North American natural gas market is increasing.    According to the EIA, in 2005, North American LNG imports were sourced from Trinidad and Tobago, Algeria, Egypt, Nigeria, Oman, Qatar and Malaysia. Currently, there are five onshore receiving terminals in continental North America with a combined natural gas sendout capacity of approximately

 

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4.75 Bcf/d, or about 6% of total North American natural gas consumption. The EIA expects that LNG will represent 17% of the North American natural gas market by 2030 if the capability to receive LNG can be expanded. As of December 2006, six additional LNG receiving terminals with an aggregate send-out capacity of 11 Bcf/d were under construction in North America. By contrast, the EIA reports that in 2004 Japan imported more than 97% of its natural gas as LNG, which illustrates LNG’s acceptance in global markets.

LNG Supply Chain

The LNG supply chain can be divided into five major phases:

Production: Natural gas is produced and transported via pipeline to natural gas liquefaction facilities located along the coast of the producing country.

Liquefaction: Once delivered to the liquefaction facility, the natural gas is supercooled to a temperature of -260 degrees Fahrenheit, transforming the gas into a liquid  1/600th the volume of its gaseous state.

Shipping: LNG is loaded onto specially designed, double-hulled LNG carriers and transported overseas from the liquefaction facility to the receiving terminal.

Regasification: In receiving terminals (either onshore or aboard specialized LNG carriers), the LNG is returned to its gaseous state, or regasified.

Storage, Transportation and Marketing: Once regasified, the natural gas is stored in specially designed facilities or transported to natural gas consumers via pipelines.

The following diagram illustrates the flow of natural gas and LNG from production to end use marketing.

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Worldwide Natural Gas Reserves

Worldwide proved natural gas reserves as of January 1, 2005 were estimated to be 6,043 Tcf, according to the EIA. The following chart displays the natural gas reserves of countries with more than 25 Tcf of proved reserves as estimated by the EIA. The chart also highlights the current and potential future LNG exporters. Current LNG exporters hold 33% of total proved natural gas reserves. Russia, Iran, Saudi Arabia, Venezuela, Iraq and Norway have 53% of total proved natural gas reserves and access to coastline such that they could become LNG exporters under appropriate economic and political conditions.

 

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Table of Contents
Index to Financial Statements

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Source: EIA and Cheniere research. Proved reserves as of January 1, 2005.

LNG Exporters

According to GIIGNL, as of 2005, there were 76 “trains,” or production units, in 13 countries capable of producing approximately 23.4 Bcf/d of LNG. LNG production capacity grew by over 45% during the 2000 to 2005 period. We estimate that liquefaction capacity will reach approximately 38 Bcf/d in 2010.

As of 1995, the Asia Pacific region, including Indonesia, Malaysia, Australia, Brunei and the United States via Alaska, represented approximately 73% of LNG exports. By 2005, these countries only accounted for 46% of global exports, with the Middle East Gulf increasing its share of global LNG trade from 7% to 23% and the Atlantic Basin increasing its share from 20% to 31%. From 1995 to 2005, LNG exports grew at an 8% compound annual growth rate. In 2005, Qatar became the third largest exporting country, with 14% of total LNG exports. The following table lists the LNG exporting countries.

 

Country

   1995 Exports    

2005 Exports

 
    

(Bcf/d)

   (Bcf/d)    % of Total  

Indonesia

   3.3    3.1    16 %

Malaysia

   1.3    2.8    15 %

Qatar

      2.7    14 %

Algeria

   1.7    2.4    13 %

Australia

   1.0    1.6    9 %

Trinidad and Tobago

      1.3