Sabine Pass LNG S-4/A Registration of securities issued in business combination transactions (amended)

As filed with the Securities and Exchange Commission on May 29, 2007

Registration No. 333-138916

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 4

TO

FORM S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Sabine Pass LNG, L.P.

(Exact name of registrant as specified in its charter)

Delaware	2813	20-0466069
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

700 Milam Street, Suite 800

Houston, Texas 77002

(713) 375-5000

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

Don A. Turkleson

Chief Financial Officer

700 Milam Street, Suite 800

Houston, Texas 77002

(713) 375-5000

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

Copy to:

Geoffrey K. Walker

Andrews Kurth LLP

600 Travis, Suite 4200

Houston, Texas 77002

(713) 220-4200

Approximate date of commencement of proposed sale of the securities to the public:    As soon as practicable after this registration statement becomes effective.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, 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, 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.  ¨

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 Commission, acting pursuant to said Section 8(a), may determine.

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 it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED MAY 29, 2007

PROSPECTUS

SABINE PASS LNG, L.P.

Offer to Exchange

$550,000,000 of 7 ¹/4% Senior Secured Notes due 2013

that have been registered under the Securities Act of 1933

for

a like amount of 7 ¹/4% Senior Secured Notes due 2013

that have not been registered under the Securities Act of 1933

and

$1,482,000,000 of 7 ¹/2% Senior Secured Notes due 2016

that have been registered under the Securities Act of 1933

for

a like amount of 7 ¹/2% Senior Secured Notes due 2016

that have not been registered under the Securities Act of 1933

THE EXCHANGE OFFER WILL EXPIRE AT 5:00 PM, NEW YORK

CITY TIME, ON [                    ], UNLESS WE EXTEND THE DATE

Terms of the Exchange Offer

• We are offering to exchange up to $2,032 million in aggregate principal amount of our outstanding 7 ¹/4% Senior Secured Notes due 2013 and 7 ¹/2% Senior Secured Notes due 2016, which were issued on November 9, 2006 in a transaction exempt from registration under the Securities Act of 1933, as amended, or the Securities Act, and which we refer to as the 2013 initial notes and the 2016 initial notes, respectively, and collectively the initial notes, for a like aggregate principal amount of our 7 ¹/4% Senior Secured Notes due 2013 and 7 ¹/2% Senior Secured Notes due 2016, which we refer to as the 2013 notes and the 2016 notes, respectively, and collectively the notes, the issuance of which will be registered under the Securities Act. The initial notes were issued, and the notes will be issued, under an indenture dated as of November 9, 2006.

• We will exchange an equal principal amount of notes for all outstanding initial notes that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer.

• The terms of the notes are substantially identical to those of the outstanding initial notes, except that the transfer restrictions and registration rights relating to the initial notes do not apply to the notes.

• You may withdraw tenders of initial notes at any time prior to the expiration of the exchange offer.

• The exchange of notes for initial notes will not be a taxable transaction for U.S. federal income tax purposes.

• We will not receive any cash proceeds from the exchange offer.

• The initial notes are, and the notes will be, fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by all of our future domestic restricted subsidiaries.

• There is no established trading market for the notes or the initial notes, and we do not intend to apply for listing of the notes on any national securities exchange or for quotation through any quotation system. However, the notes are expected to be eligible to trade in The PORTAL^SM Market, or PORTAL, a subsidiary of The Nasdaq Stock Market, Inc.

Terms of the Notes

• We will pay interest on the notes on each May 30 and November 30, commencing May 30, 2007.

• The 2013 notes and the 2016 notes will mature on November 30, 2013 and November 30, 2016, respectively.

• We may redeem the 2013 notes and the 2016 notes, in whole or in part, at any time prior to maturity at the redemption prices described in this prospectus, which will include a make-whole premium. In addition, prior to November 30, 2009, we may redeem up to 35% of the 2013 notes and the 2016 notes with the net cash proceeds of one or more equity offerings. Redemption prices are set forth in this prospectus under “Description of Notes—Optional Redemption.”

• There is no sinking fund for the notes.

• The notes will be secured by a first-priority security interest (subject to certain permitted liens) in our equity interests and substantially all of our assets. The notes will be our senior secured obligations and will rankpari passu in right of payment with all of our existing and future senior indebtedness and senior in right of payment to all of our subordinated indebtedness.

This investment involves risks. Please read “Risk Factors” beginning on page 17 for a discussion of certain risks that you should consider prior to tendering your outstanding initial notes in the exchange offer.

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.

Each broker-dealer that receives notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of notes received in exchange for initial notes where such initial notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of not less than 90 days after the consummation of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. Please read “Plan of Distribution.”

The date of the prospectus is [                    ].

TABLE OF CONTENTS

	Page
SUMMARY	1
RISK FACTORS	17
USEOF PROCEEDS	33
SELECTED HISTORICAL FINANCIAL DATA	34
MANAGEMENT’S DISCUSSIONAND ANALYSISOF FINANCIAL CONDITIONAND RESULTSOF OPERATIONS	35
BUSINESS	46
DESCRIPTIONOF PRINCIPAL PROJECT DOCUMENTS	62
MANAGEMENT	75
CERTAIN RELATIONSHIPSAND RELATED TRANSACTIONS	78
SECURITY OWNERSHIPOF CERTAIN BENEFICIAL OWNERSAND MANAGEMENT	80
THE EXCHANGE OFFER	81
DESCRIPTIONOF NOTES	92
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS	151
PLANOF DISTRIBUTION	155
LEGAL MATTERS	156
EXPERTS	156
INDEPENDENT ENGINEER	156
AVAILABLE INFORMATION	156
FORWARD-LOOKING STATEMENTS	157
PRESENTATIONOF INFORMATION	158
INDEXTO FINANCIAL STATEMENTS	F-1
APPENDIX A—INDEPENDENT ENGINEER’S REPORT	A-1

You should rely only on the information contained in this document. We have not authorized anyone to provide you with information that is different. This document may only be used where it is legal to sell these securities. The information in this document may be accurate only on the date of this document.

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SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. Because this is only a summary, it does not contain all of the information that you should consider before making a decision to participate in the exchange offer. You should carefully read the entire prospectus, especially “Risk Factors” beginning on page 17 and our financial statements and the related notes, before deciding to participate in the exchange offer. Unless otherwise indicated, financial information included in this prospectus is presented on an historical basis. As used in this prospectus, unless we indicate otherwise or the context otherwise requires, the terms Sabine Pass LNG, “we,” “our,” “us” and similar terms refer to Sabine Pass LNG, L.P.

Overview

We are an indirect subsidiary of Cheniere Energy, Inc., or Cheniere, which owns a 90.6% interest in us, created to develop, own and operate the Sabine Pass liquefied natural gas, or LNG, receiving terminal currently under construction in western Cameron Parish, Louisiana on the Sabine Pass Channel. The entire 4.0 billion cubic feet per day, or Bcf/d, of regasification capacity that will be available at our LNG receiving terminal upon completion of construction has been fully reserved under three 20-year terminal use agreements, or TUAs, under which the customers are generally required to pay fixed monthly fees, whether or not they use the terminal. Provided our LNG receiving terminal has achieved the required level of commercial operation, which we expect will occur in the third quarter of 2008, these 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;

• 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; and

• 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 commencing on the date of commercial operations completion.

Our LNG Receiving Terminal

In 2003, we were formed by Cheniere to develop our LNG receiving terminal. The initial phase, or Phase 1, of our LNG receiving terminal was designed, and permitted by the Federal Energy Regulatory Commission, or FERC, with a regasification capacity of 2.6 Bcf/d, three LNG storage tanks with an aggregate LNG storage capacity of 10.1 billion cubic feet, or Bcf, and two unloading docks capable of handling the largest LNG carriers currently being operated or built. In July 2006, we received approval from the FERC to increase the regasification capacity of our 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 entire FERC-approved expansion as Phase 2. The first stage of the Phase 2 expansion will include the addition of a fourth and fifth LNG storage tank, 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.

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Although we are still in the process of constructing our LNG receiving terminal, we have already entered into three TUAs, through which Total, Chevron and Cheniere Marketing have reserved, in aggregate, the entire 4.0

Bcf/d of LNG regasification capacity that will be available upon completion of Phase 1 and Phase 2 – Stage 1 of our LNG receiving terminal. Payment obligations under our TUAs have also been guaranteed by our customers’ respective parent companies, Total, S.A. (up to $2.5 billion of fees payable by Total), Chevron Corporation (up to 80% of fees payable by Chevron) and Cheniere (100% of fees payable by Cheniere Marketing).

Construction of our LNG receiving terminal began in March 2005. During the second quarter of 2008, we expect to complete construction and cool down of the first two tanks, to complete related equipment installation and specified checks and tests, and to achieve a sustained revaporized natural gas sendout at a significant rate for a preagreed period of time (currently provided to be a rate of at least 2.0 Bcf/d for a minimum sustained test period of at least 24 hours), which we refer to as Phase 1 Target Completion. We expect to complete construction and commissioning of the third tank and the rest of Phase 1, and to achieve the full 2.6 Bcf/d of Phase 1 regasification capacity, during the third quarter of 2008. LNG regasification operations relating to the Phase 2 – Stage 1 expansion are expected to commence by April 2009. We expect to complete all of Phase 2 – Stage 1, including construction and commissioning of the fourth and fifth tanks, and to achieve full operability at 4.0 Bcf/d and aggregate storage capacity of approximately 16.8 Bcf during the third quarter of 2009.

Our cost to construct Phase 1 of our LNG facility is currently estimated at approximately $900 million to $950 million, before financing costs. Phase 2 – Stage 1 is estimated to cost approximately $500 million to $550 million, before financing costs. Our 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 our construction schedule. See “Description of Principal Project Documents.” As of March 31, 2007, we had paid $615.0 million and $73.5 million of Phase 1 and Phase 2 – Stage 1 construction costs, respectively.

Business Strategy

Our primary business objective is to generate stable cash flows by completing construction of our LNG receiving terminal so that terminal operations can commence and we can generate steady and reliable revenues under long-term TUAs.

Strengths

We believe that we have several strengths and advantages in pursuing our business strategy, including:

• our contracted and stable cash flows under three long-term TUAs;

• our solid arrangements with Bechtel Corporation, or Bechtel, for the construction of our LNG receiving terminal;

• what we believe is one of the best available North American sites for our LNG receiving terminal;

• ample access, currently under development, to natural gas transmission pipelines;

• economies of scale in operation of our LNG receiving terminal;

• an environmentally sound and community friendly approach in developing our LNG receiving terminal;

• our team of professionals with extensive experience in the LNG industry;

• a comprehensive collateral package that benefits the notes; and

• the availability of reserve funds that offer multiple sources of liquidity.

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Illustrative Cash Flow Summary

The information set forth below represents our anticipated results of operations, including the projected revenues under our 20-year TUAs with Total, Chevron and Cheniere Marketing, for 2010, the first full year of 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 projected. We cannot give any assurance that these assumptions are correct or that this information will reflect actual results. Accordingly, this financial estimate 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 payments of principal and interest on the notes may be adversely affected. For additional information relating to these financial estimates, please read “Risk Factors—Risks Relating to the Exchange Offer and the Notes—Our financial estimates, including our illustrative cash flow summary, are based on certain assumptions that may not materialize.”

(Dollars in millions)	2010
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(3)		(36.7	)
Assumed commissioning costs(4)		—
State and local taxes		(9.9	)
EBITDA(5)	$	460.5
EBITDA/Interest(6)		3.1x
Total Debt/ EBITDA(7)		4.4x

(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 operating expenses and maintenance capital expenditures are as estimated by us and the Independent Engineer. See “Summary of Independent Engineer’s Report,” below, for more information. Maintenance capital expenditures estimated by us at $1.5 million per year beginning in 2009, escalating with inflation at 2.5% annually thereafter, are not included in this table.

(4) We anticipate that these commissioning costs will be paid before the third quarter of 2009.

(5) Calculated as total 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 weighted-average fixed interest rate of 7.432% paid semi-annually.

(7) Assumes total debt of $2,032 million.

Assuming payments under the 20-year TUAs with Total, Chevron and Cheniere Marketing are made as contractually stipulated, we expect (i) the Total TUA to provide annual revenues of approximately $125 million for 20 years commencing April 1, 2009, (ii) the Chevron TUA to provide annual revenues of approximately $125 million for 20 years commencing July 1, 2009 and (iii) the Cheniere Marketing TUA to provide annual revenues of approximately $250 million for at least 19 years commencing January 1, 2009,plus initial revenues of $5

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million per month during 2008 commencing on the date of commercial operations completion. The Independent Engineer has estimated that the total annual operating expenses for our LNG receiving terminal will be approximately $37 million per year to support the full 4.0 Bcf/d of receiving capacity. Based on these expected TUA revenues and operating expenses, we believe that our LNG receiving terminal will generate approximately $461 million in EBITDA in 2010.

The operating expenses set forth in the table above for 2010 may be higher in later years due to numerous factors, such as increased maintenance costs of our LNG receiving terminal as the facility ages. As a result, the EBITDA forecast for 2010 may not be indicative of our EBITDA in periods thereafter. In addition, approximately one-half of our forecast revenues are attributable to Cheniere Marketing, which is a small, developing company with virtually no operating history. See “Risk Factors—Risks Relating to Development and Operation of Our Business—If and when the applicable commercial start dates under the TUAs are achieved, we will become dependent upon our TUA counterparties, including cash flows from the Cheniere Marketing TUA, for substantially all of our revenues and cash flows.” We do not expect to generate sufficient cash flow from operations to repay the notes upon maturity without additional refinancing, which may not be available on terms reasonably acceptable to us or at all. See “Risk Factors—Risks Relating to the Exchange Offer and the Notes—To service our indebtedness, we will require significant amounts of cash. Our ability to generate cash will depend on many factors beyond our control.”

Our independent auditor has not reviewed the foregoing illustrative cash flow summary and, accordingly, does not express an opinion or any other form of assurance on it. Holders of the notes will not be provided with any revised illustrative cash flow summary. We expressly disclaim any duty to update the illustrative cash flow summary under any circumstances.

Non-GAAP Financial Measure

Our 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 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.

Our 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. Our EBITDA excludes some, but not all, items that affect net income and operating income, and it does not include capital expenditures and other non-operating items that require capital expenditures. In addition, these expenditures excluded from EBITDA may, over time, be material to our business and may have a negative impact on the cash available to make interest payments on the notes and to repay our indebtedness. These EBITDA measures may vary among companies. Therefore, our EBITDA may not be comparable to similarly titled measures of other companies.

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Summary of Independent Engineer’s Report

This prospectus contains a report by Stone & Webster Management Consultants, Inc., or the Independent Engineer. The Independent Engineer has prepared a report that analyzes certain technical, environmental and economic aspects of our LNG receiving terminal. This report includes, among other things, discussions of the technology used at the LNG receiving terminal, engineering and construction execution issues and costs, operating plans, environmental permitting status, and a technical review of the documents and agreements relating to our LNG receiving terminal. A copy of the report is attached as Appendix A to this prospectus and should be read in its entirety. 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.

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. The persons responsible for the assumptions contained in the report 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, our ability to make payments of principal and interest on the notes may be adversely affected.

Our independent auditor has not reviewed the Independent Engineer’s report and, accordingly, does not express an opinion or any other form of assurance on it. Holders of the notes will not be provided with any revised report from the Independent Engineer. We expressly disclaim any duty to update the Independent Engineer’s report under any circumstances.

Below is a summary of the conclusions expressed by the Independent Engineer in its report. This is merely a summary and is subject to the information contained, and the assumptions made, in the Independent Engineer’s report. The Independent Engineer’s report should be read in its entirety in order for the reader to understand the basis of the conclusions and the assumptions upon which they are based.

Certain terms used in the summary below are defined in the Independent Engineer’s report. On the basis of its studies, analyses and investigations of our LNG receiving terminal and the assumptions set forth in the Independent Engineer’s report, the Independent Engineer is of the opinion that:

• The Phase 1 Project is technically viable;

• The Phase 1 Project Budget is reasonable;

• The Phase 1 Schedule is reasonable;

• The Phase 1 Project has been approved by the FERC, indicating compliance with environmental regulations and that environmental risks are low;

• The Phase 1 Project contracting strategy is reasonable and minimizes the strain on Sabine Pass LNG, which is a development stage company;

• The Phase 1 EPC contract provides a suitable basis for contracting the required services;

• The Phase 1 Project will provide ample availability to service the aggregate 2.0 Bcf/d export capacity requirements under the Total and Chevron TUAs;

• The Phase 2 – Stage 1 Expansion of Sabine Pass poses negligible risk to the timely completion and operation of the Phase 1 Project;

• The Phase 2 – Stage 1 Expansion is technically feasible and viable;

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• The Phase 2 – Stage 1 Budget is reasonable and generally consistent with that for the Phase 1 Project;

• The Phase 2 – Stage 1 Schedule is reasonable;

• The Phase 2 – Stage 1 Project has been approved by the FERC, indicating compliance with environmental regulations and that environmental risks are low;

• The Phase 2 – Stage 1 Project contracting strategy provides Sabine Pass LNG with maximum flexibility in Phase 2 Project execution;

• The Phase 2 – Stage 1 construction contracts provide a suitable basis for contracting the required services without impinging on the Phase 1 Project; and

• The Phase 2 – Stage 1 Project will increase the overall export capacity to a maximum peak rate of 4.0 Bcf/d and a long-term sustainable capacity of at least approximately 3.5 Bcf/d.

Organizational Structure

We are the operating subsidiary of Cheniere that was created to develop, own and operate the Sabine Pass LNG receiving terminal. Our general partner has sole responsibility and authority for conducting our business and for managing our operations. The directors and officers of our general partner are also officers of Cheniere, except for one independent director. See “Management.” The following chart shows the ownership of our partnership:

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Contractual Relationships

The following chart illustrates several of our key contractual relationships. See “Description of Principal Project Documents” and “Certain Relationships and Related Transactions” for additional information regarding the agreements listed below.

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The Exchange Offer

On November 9, 2006, we completed a private offering of the initial notes. As part of the private offering, we entered into a registration rights agreement with the representative of the initial purchasers of the initial notes in which we agreed, among other things, to deliver this prospectus to you and to use our commercially reasonable efforts to cause the registration statement to be effective within 270 days of the issue date of the initial notes and to complete the exchange offer within 30 days thereafter. The following is a summary of the exchange offer.

Original Notes $550 million aggregate principal amount of 7 ¹/4% Senior Secured Notes due 2013, which were issued in a private placement on November 9, 2006

$1,482 million aggregate principal amount of 7 ¹/2% Senior Secured Notes due 2016, which were issued on November 9, 2006

Notes 7 ¹/4% Senior Secured Notes due November 30, 2013 and 7 ¹/2% Senior Secured Notes due November 30, 2016. The terms of the notes are substantially identical to those terms of the outstanding initial notes, except that the transfer restrictions, registration rights and provision for additional interest relating to the initial notes do not apply to the notes.

Exchange Offer We are offering to exchange up to $2,032 million aggregate principal amount of our notes ($550 million of 7 ¹/4% Senior Secured Notes due 2013 and $1,482 million of 7 ¹/2% Senior Secured Notes due 2016) that have been registered under the Securities Act for an equal amount of our outstanding initial notes that have not been registered under the Securities Act to satisfy our obligations under the registration rights agreement.

The notes will evidence the same debt as the initial notes and will be issued under and be entitled to the benefits of the same indenture that governs the initial notes. Holders of the initial notes do not have any appraisal or dissenter rights in connection with the exchange offer. Because the notes will be registered, the notes will not be subject to transfer restrictions or the provisions for additional interest, and holders of initial notes that have tendered and had their initial notes accepted in the exchange offer will have no registration rights.

Expiration Date The exchange offer will expire at 5:00 p.m., New York City time, on [                    ], unless we decide to extend it. We do not currently intend to extend the exchange offer.

Conditions to the Exchange Offer The exchange offer is subject to customary conditions, which we may waive. Please read “The Exchange Offer—Conditions to the Exchange Offer” for more information regarding the conditions to the exchange offer.

Procedures for Tendering Initial Notes Unless you comply with the procedures described under the caption “The Exchange Offer—Procedures for Tendering—Guaranteed

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Delivery,” you must do one of the following on or prior to the expiration of the exchange offer to participate in the exchange offer:

• tender your initial notes by sending the certificates for your initial notes, in proper form for transfer, a properly completed and duly executed letter of transmittal, with any required signature guarantees, and all other documents required by the letter of transmittal, to The Bank of New York, as registrar and exchange agent, at the address listed under the caption “The Exchange Offer—Exchange Agent”; or

• tender your initial notes by using the book-entry transfer procedures described below and transmitting a properly completed and duly executed letter of transmittal, with any required signature guarantees, or an agent’s message instead of the letter of transmittal, to the exchange agent. In order for a book-entry transfer to constitute a valid tender of your initial notes in the exchange offer, The Bank of New York, as registrar and exchange agent, must receive a confirmation of book-entry transfer of your initial notes into the exchange agent’s account at The Depository Trust Company prior to the expiration of the exchange offer. For more information regarding the use of book-entry transfer procedures, including a description of the required agent’s message, please read the discussion under the caption “The Exchange Offer—Procedures for Tendering—Book-Entry Transfer.”

Guaranteed Delivery Procedures If you are a registered holder of the initial notes and wish to tender your initial notes in the exchange offer, but

• the initial notes are not immediately available,

• time will not permit your initial notes or other required documents to reach the exchange agent before the expiration of the exchange offer, or

• the procedure for book-entry transfer cannot be completed prior to the expiration of the exchange offer,

then you may tender your initial notes by following the procedures described under the caption “The Exchange Offer—Procedures for Tendering—Guaranteed Delivery.”

Special Procedures for Beneficial Owners If you are a beneficial owner whose initial notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your initial notes in the exchange offer, you should promptly contact the person in whose name the initial notes are registered and instruct that person to tender on your behalf.

If you wish to tender in the exchange offer on your own behalf, prior to completing and executing the letter of transmittal and delivering the certificates for your initial notes, you must either make

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appropriate arrangements to register ownership of the initial notes in your name or obtain a properly completed bond power from the person in whose name the initial notes are registered.

Withdrawal; Non-Acceptance You may withdraw any initial notes tendered in the exchange offer at any time prior to 5:00 p.m., New York City time, on [                    ]. If we decide for any reason not to accept any initial notes tendered for exchange, the initial notes will be returned to the registered holder at our expense promptly after the expiration or termination of the exchange offer. In the case of initial notes tendered by book-entry transfer into the exchange agent’s account at The Depository Trust Company, any withdrawn or unaccepted initial notes will be credited to the tendering holder’s account at The Depository Trust Company. For further information regarding the withdrawal of tendered initial notes, please read “The Exchange Offer—Withdrawal Rights.”

U.S. Federal Income Tax Considerations The exchange of notes for initial notes in the exchange offer will not be a taxable transaction for U.S. federal income tax purposes. Please read the discussion under the caption “Material United States Federal Income Tax Considerations” for more information regarding the tax consequences to you of the exchange offer.

Use of Proceeds The issuance of the notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement.

Fees and Expenses We will pay all of the expenses incident to the exchange offer.

Exchange Agent We have appointed The Bank of New York as exchange agent for the exchange offer. You can find the address, telephone number and fax number of the exchange agent under the caption “The Exchange Offer—Exchange Agent.”

Resales of Notes Based on interpretations by the staff of the SEC, as set forth in no-action letters issued to third parties that are not related to us, we believe that the notes you receive in the exchange offer may be offered for resale, resold or otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act so long as:

• the notes are being acquired in the ordinary course of business;

• you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the notes issued to you in the exchange offer;

• you are not our affiliate; and

• you are not a broker-dealer tendering initial notes acquired directly from us for your account.

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The SEC has not considered this exchange offer in the context of a no-action letter, and we cannot assure you that the SEC would make similar determinations with respect to this exchange offer. If any of these conditions are not satisfied, or if our belief is not accurate, and you transfer any notes issued to you in the exchange offer without delivering a resale prospectus meeting the requirements of the Securities Act or without an exemption from registration of your notes from those requirements, you may incur liability under the Securities Act. We will not assume, nor will we indemnify you against, any such liability. Each broker-dealer that receives notes for its own account in exchange for initial notes, where the initial notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such notes. Please read “Plan of Distribution.”

Please read “The Exchange Offer—Resales of Notes” for more information regarding resales of the notes.

Consequences of Not Exchanging Your Initial Notes If you do not exchange your initial notes in this exchange offer, you will no longer be able to require us to register your initial notes under the Securities Act, except in the limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer your initial notes unless we have registered the initial notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

For information regarding the consequences of not tendering your initial notes and our obligation to file a registration statement, please read “The Exchange Offer—Consequences of Failure to Exchange Outstanding Securities” and “Description of Notes.”

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Description of Notes

The terms of the notes and those of the outstanding initial notes are substantially identical, except that the transfer restrictions and registration rights relating to the initial notes do not apply to the notes. As a result, the notes will not bear legends restricting their transfer and will not have the benefit of the registration rights and special interest provisions contained in the initial notes. The notes represent the same debt as the initial notes for which they are being exchanged. Both the initial notes and the notes are governed by the same indenture. When we use the term “notes” in this prospectus, unless the context otherwise requires, the term includes the initial notes and the notes issued pursuant to the exchange offer.

The following is a summary of the terms of the notes. It may not contain all of the information that is important to you. For a more detailed description of the notes, please read “Description of Notes.”

Issuer Sabine Pass LNG, L.P.

Notes Offered $550 million aggregate principal amount of 7 ¹/4% Senior Secured Notes due 2013.

$1,482 million aggregate principal amount of 7 ¹/2% Senior Secured Notes due 2016.

Maturity Date 2013 notes: November 30, 2013

2016 notes: November 30, 2016

The notes will not amortize prior to the Maturity Date.

Interest Payment Dates May 30 and November 30 of each year, commencing on May 30, 2007.

Interest 7 ¹/4% per annum on the 2013 notes and 7 ¹/2% per annum on the 2016 notes, payable semiannually in arrears. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Guarantees The notes will be guaranteed by all of our future domestic restricted subsidiaries. We currently have no subsidiaries. See “Description of Notes—The Note Guarantees.”

Ranking The notes are our senior secured obligations and:

• rankpari passu in right of payment with all of our other existing and future senior indebtedness; and

• rank senior in right of payment to all of our subordinated indebtedness.

We have no indebtedness outstanding other than the initial notes.

Optional Redemption At any time and from time to time, we may redeem some or all of the 2013 notes at a redemption price equal to 100% of the principal amount plus a make-whole premium, plus accrued and unpaid interest and additional interest, if any, to the redemption date.

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At any time and from time to time, we may redeem some or all of the 2016 notes at a redemption price equal to 100% of the principal amount plus a make-whole premium, plus accrued and unpaid interest and additional interest, if any, to the redemption date.

Until November 30, 2009, we may redeem up to 35% of the principal amount of the 2013 notes and the 2016 notes originally issued with the net cash proceeds of one or more equity offerings by us with the proceeds that we retain or that are contributed to us, as applicable, at par plus a premium equal to the coupon, plus accrued and unpaid interest and additional interest, if any, as long as at least 65% of the aggregate principal amount of the notes remains outstanding immediately after such optional redemption and such optional redemption occurs within 90 days of the date of the closing of such equity offering.

Mandatory Redemption If we sell certain assets or experience certain events of loss, we must offer to purchase the notes at the prices determined as stated under “Description of Notes—Repurchase at the Option of Holders.”

Change of Control If a change of control of our general partner occurs, we are required to offer to repurchase all or a portion of such holder’s notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest and additional interest, if any, as of the date of repurchase.

Collateral Our obligations under the notes are secured on a first-priority basis (subject to certain permitted liens) by a security interest in our equity interests and substantially all of our assets, including a pledge of the stock of our future subsidiaries (provided that the pledge of voting stock of our future foreign subsidiaries will be limited to 65% of the voting stock owned by us or any guarantor). See “Description of Notes—Security.”

Construction Period Debt Service Reserve Account We have deposited $335 million in a debt service reserve account, which will be withdrawn when necessary to pay the first five interest payments on the notes.

Cash Waterfall We have deposited approximately $887 million from the sale of the initial notes in a construction account, which, until Phase 1 Target Completion, will only be applied to pay construction and startup costs of the project and to pay other expenses incidental for us to complete construction of the project. Following Phase 1 Target Completion, any amount remaining in the construction account will be transferred to a revenue account.

All revenues received by us will be deposited in a revenue account and will be applied as described in “Pre-Completion Account Flows” and “Post-Completion Account Flows” below.

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Pre-Completion Account Flows Prior to Phase 1 Target Completion, revenues received by us will be applied in the following manner:

• first, to pay obligations, if any, under the assumption agreement, as described under “Certain Relationships and Related Transactions—Assumption Agreement,” which we refer to as the assumption agreement;

• second, to the extent that amounts on deposit in the debt service reserve account are not sufficient to pay interest on the notes on the next interest payment date, to such account in an amount sufficient to make such payment; and

• third, to the construction account (i) to fund the construction and start-up costs of our LNG receiving terminal; (ii) to pay other expenses (including taxes) incidental for us to complete construction of our LNG receiving terminal; and (iii) to be transferred to other project accounts.

Post-Completion Account Flows After Phase 1 Target Completion, revenues received by us will be applied in the following manner:

• first, to fund the operating account with amounts sufficient to cover the succeeding 45 days of operation and maintenance expenses, maintenance capital expenditures and obligations, if any, under the assumption agreement and a state tax sharing agreement;

• second, 1/6th of the amount of interest due on the notes on the next interest payment date (plus any shortfall from any such month subsequent to the preceding interest payment date) will be transferred to a debt payment account;

• third, to pay outstanding principal then due and payable on the notes;

• fourth, to pay taxes payable by us or the guarantors and permitted payments in respect of taxes;

• fifth, to replenish the debt service reserve account when such account is not funded 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 notes; and

• sixth, for all other purposes permitted by the indenture including restricted payments, subject to the limitations contained in the indenture.

Covenants The indenture governing the notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

• incur additional indebtedness or issue preferred stock;

• make certain investments or pay dividends or distributions on our capital stock or subordinated indebtedness or purchase or redeem or retire capital stock;

• sell or transfer assets, including capital stock of our restricted subsidiaries;

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• restrict dividends or other payments by restricted subsidiaries;

• incur liens;

• enter into transactions with affiliates;

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

• enter into sale and leaseback transactions.

These covenants are subject to a number of important limitations and exceptions that are described later in this prospectus under the caption “Description of Notes—Certain Covenants.”

Restricted Payments We will be permitted to make payments on subordinated debt, make distribution to our partners, purchase any equity interest in an affiliate and make restricted investments with any amounts of available cash, which includes revenues available after payment of construction costs and other capital expenditures, payments of required principal and interest on indebtedness and payment of operation and maintenance expenses. Such payments can be made as long as no default or event of default under the indenture has occurred and is continuing; Phase 1 has been completed in accordance with the target completion date performance standards set forth in the EPC contract with Bechtel; we would be permitted to incur at least $1.00 of additional indebtedness at the time of the payment and after giving pro forma effect thereto; the operating period debt service reserve account has at least six months of interest funded; and the debt payment account has on deposit the amount required at such time.

Transfer Restrictions; Absence of a Public Market for the Notes The notes issued pursuant to this exchange offer will generally be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development or liquidity of any market for the notes.

Governing Law The indenture, the notes and related security documents are governed by, and construed in accordance with, the laws of the State of New York, while the real property mortgage is governed by the laws of the State of Louisiana.

Risk Factors

See “Risk Factors” for a discussion of certain factors that you should carefully consider before deciding to participate in the exchange offer.

Executive Offices

Our principal executive offices are located at 700 Milam Street, Suite 800, Houston, Texas 77002. Our telephone number is (713) 375-5000.

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Summary Selected Historical Financial Data

The following tables set forth our selected financial data for the periods and at the dates indicated. The summary statement of operations data for the years ended December 31, 2004, 2005 and 2006, and the balance sheet information at December 31, 2005 and 2006 are derived from our audited financial statements, which are included elsewhere in this prospectus. The summary statement of operations data for the three months ended March 31, 2007 and 2006 and the balance sheet information at March 31, 2007 are derived from our unaudited financial statements, which are included elsewhere in this prospectus. The summary statement of operations data for the period from October 20, 2003 (inception) through December 31, 2003 and the summary balance sheet information at December 31, 2003 and 2004 have been derived from our audited financial statements, which are not included in this prospectus. 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 tables from, and that information should be read together with and is qualified in its entirety by reference to, the 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.”

(Dollars in thousands)	Period from October 20, 2003 (inception) to December 31, 2003			Year ended December 31,									Three Months Ended March 31,
				2004			2005			2006			2007			2006
Revenues	$	—		$	—		$	—		$	—		$	—		$	—
Expenses		2,763			4,682			4,711			10,265			1,860			1,590
Loss from operations		(2,763	)		(4,682	)		(4,711	)		(10,265	)		(1,860	)		(1,590	)
Other income (expense)(1)		—			28			456			(50,495	)		(11,050	)		810
Net loss	$	(2,763	)	$	(4,654	)	$	(4,255	)	$	(60,760	)	$	(12,910	)	$	(780	)
Ratio of earnings to fixed charges(2)		—			—			—			—			—			—

(Dollars in thousands)	December 31,								March 31, 2007
	2003		2004		2005		2006
Cash and cash equivalents (unrestricted)	$	—	$	21,822	$	—	$	—	$	—
Non-current restricted cash and cash equivalents		—		—		—		982,613		882,919
Restricted cash and cash equivalents		—		—		8,871		176,324		209,645
Total assets		101		23,316		309,135		1,858,111		1,915,487
Long-term debt		—		—		37,377		2,032,000		2,032,000
Deferred revenues		—		22,000		40,000		40,000		40,000
Total other long-term liabilities		2,864		17,418		120		1,149		1,154

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

(2) The ratios were computed by dividing earnings by fixed charges. For this purpose, “earnings” represent the aggregate of (a) pre-tax income from continuing operations before adjustment for minority interests in consolidated subsidiaries or income or loss from equity investees, (b) fixed charges, (c) amortization of capitalized interest, (d) distributed income of equity investees and (e) our share of pre-tax losses of equity investees for which charges arising from guarantees are included in fixed charges, net of (a) interest capitalized and (b) the minority interest in pre-tax income of subsidiaries that have not incurred fixed charges. “Fixed charges” represent the sum of (a) interest expensed and capitalized, (b) amortized premiums, discounts and capitalized expenses related to indebtedness and (c) an estimate of the interest within rental expense. As a result of reported losses, earnings were inadequate to cover fixed charges, thereby resulting in a coverage deficiency of $2.8 million for the period from October 20, 2003 (inception) to December 31, 2003, $4.7 million, $9.7 million and $83.1 million for the years ended December 31, 2004, 2005 and 2006, respectively, and $25.8 million and $3.5 million for the three months ended March 31, 2007 and 2006, respectively.

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RISK FACTORS

Before deciding to participate in the exchange offer, you should carefully consider the following risk factors. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect the development of our business, our assets, our contracts, our results of operations, our tax status, our financial condition and our prospects. As a result of any of these risks, known and unknown, you could lose all or part of your original investment in the notes.

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

• Risks Relating to Completion of our LNG Receiving Terminal, beginning on this page 17;

• Risks Relating to Development and Operation of our Business, beginning on page 20; and

• Risks Relating to the Exchange Offer and the Notes, beginning on page 27.

Risks Relating to Completion of our LNG Receiving Terminal

Our inability to timely construct and commission our LNG receiving terminal would prevent us from commencing operations when anticipated and would prevent us from realizing anticipated cash flows.

We may not complete Phase 1 or Phase 2 – Stage 1 of our 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;

• our failure to enter into satisfactory additional agreements with contractors for the rest of Phase 2 – Stage 1;

• 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 our LNG receiving terminal;

• failure to obtain all necessary governmental and third-party permits, licenses and approvals for the construction and operation of our 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 our LNG receiving terminal due to safety, environmental or security concerns; and

• local and general economic and infrastructure conditions.

Our inability to timely complete our LNG receiving terminal, including as a result of any of the foregoing factors, could prevent us 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.

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We may experience cost overruns and delays in the completion of Phase 1 or Phase 2 – Stage 1 of our 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.

Our construction costs for Phase 1 and 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 increased spending to maintain construction schedules. We may also incur commissioning costs in excess of our forecast. As of April 30, 2007, change orders for $132.3 million had 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 U.S. in almost 25 years, as a result of which there are limited benchmarks against which to compare our estimates.

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 we fail 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, we 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 us 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, or 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.

We are dependent on Bechtel and other contractors for the successful completion of our 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 our 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 us. Our contractors’ ability to perform successfully under their contracts is dependent on a number of factors, including their ability to:

• design and engineer our 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

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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.

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 our LNG receiving terminal, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. 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 byforce 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 Project Documents” 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, we 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 payments on the notes.

To commission our LNG receiving terminal, we must purchase and process LNG. We have not previously purchased or processed any LNG.

Our LNG receiving terminal must undergo a commissioning process for our 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.

Our construction cost estimates do not include the costs of acquiring this LNG (other than a minor portion we refer to as “heel” LNG) at our LNG receiving terminal, which we have projected will be approximately $157.5 million. Our actual cost to obtain LNG for the commissioning process could exceed our estimates, and the overrun could be significant.

We face several principal risks associated with this required purchase of LNG, including the following:

• we may be unable to enter into a contract for the purchase of the LNG needed for commissioning and may be unable to obtain tankers to deliver such LNG on terms reasonably acceptable to us or at all. Although we expect to contract with Cheniere Marketing to provide the LNG and the tankers, we have not negotiated any such contract at this time with Cheniere Marketing or any other third party;

• we will bear the commodity price risk associated with purchasing the LNG, holding it in inventory for a period of time and selling the regasified LNG; and

• we 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.

Our failure to obtain LNG, tankers or both, or our inability to finance the purchase of LNG needed for commissioning, would impede commencement of commercial operation at our LNG receiving terminal, which

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could delay 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.

To commissionour LNG receiving terminal,we must obtain natural gas pipeline transportation access. The required pipeline infrastructure is under development by a Cheniere entity but has not yet been constructed.

The commissioning process for our LNG receiving terminal is dependent upon completion of pipeline infrastructure to supply natural gas for power generation units prior to delivery of cool down LNG and to take away natural gas produced in the commissioning process. We expect to obtain access to the natural gas required for the commissioning process from a four-inch diameter pipeline, approximately 5,000 feet in length, that we will construct from our LNG receiving terminal to a third-party pipeline. This pipeline infrastructure has not been constructed, and its timely completion is subject to numerous risks, such as weather delays, accidents and inability to obtain required rights-of-way and governmental approvals.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development of our LNG receiving terminal or related pipeline infrastructure 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 our LNG receiving terminal. Although we have obtained NGA Section 3 authorization to construct and operate our LNG receiving terminal, such authorization is subject to ongoing conditions imposed by the FERC. We also have not obtained several other material governmental and regulatory approvals and permits required in order to construct and operate Phase 2 – Stage 1 of our LNG receiving terminal, and third parties have not obtained approvals and permits to develop related pipeline infrastructure, 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 our ability to obtain and maintain such permits or approvals. 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.

Hurricanes or other disasters could result in a delay in the completion of our 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 our 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, our LNG receiving terminal experienced construction delays and increased costs totaling approximately $36.0 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, our LNG receiving terminal or related infrastructure.

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Risks Relating to Development and Operation of our Business

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 our 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 we may not be able to make payments on the notes.

We are a development stage company with no revenues, operating cash flows or operating history. We have had net losses of $85.3 million for the period from inception through March 31, 2007. 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 our LNG receiving terminal. Any delays beyond the expected development periods for our 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.

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 March 31, 2007, Cheniere and its subsidiaries had approximately 290 full-time employees, who, for the most part, were focused on the development of three LNG receiving terminals and other complementary businesses. As construction of our LNG receiving terminal progresses, we will have to hire or otherwise arrange with Cheniere affiliates for new onsite employees to manage the facility, which will increase the personnel needed to operate the facility from 34 as of March 31, 2007 to 65 in the first quarter of 2008, at an estimated annual cost of approximately $5.3 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 and other Cheniere subsidiaries will also have to expand their administrative staffs. If our general partner is not able to successfully manage the expansion of our business, 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, including Messrs. Horton, Little and Turkleson, could have a material adverse effect on our business. In addition, our future success will depend in part on our general partner’s ability to engage, and Cheniere’s ability to attract and retain, additional qualified personnel.

We will have numerous contractual and commercial relationships, and conflicts of interest, with Cheniere and its affiliates, including Cheniere Marketing.

We have agreements to compensate and to reimburse expenses of affiliates of Cheniere. In addition, we have entered into a TUA with Cheniere Marketing, under which Cheniere Marketing will be able to derive substantially all of the economic benefits that may be generated by our LNG receiving facility beyond the payments to be received by us under our TUAs. Under its TUA, Cheniere Marketing may also require us to build a sixth LNG storage tank within four years after notification from Cheniere Marketing, provided that, among other things, we can obtain financing we consider to be reasonably acceptable. All of these agreements involve conflicts of interest between us, on the one hand, and Cheniere and its other affiliates, on the other hand.

We expect that there will be additional agreements or arrangements with Cheniere and its affiliates, including future interconnection and gas balancing 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

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where additional contracts with Cheniere and its affiliates may be necessary or desirable, additional conflicts of interest will be involved.

The interests of Cheniere could conflict with your interest. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of Cheniere, as an equity holder, might conflict with your interests as a noteholder.

We will be dependent for substantially all of our revenues and cash flows on the TUA counterparties. Cheniere Marketing has a limited operating history, limited capital, no credit rating and an unproven business strategy and may not be able to make payments to us under its TUA.

We will be 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. We are also exposed to the credit risk of the guarantors of our customers’ obligations under the TUAs in the event that we must seek recourse under a guaranty.

Cheniere Marketing has a limited operating history, limited capital, no credit rating and an unproven business strategy. Cheniere Marketing has no credit rating, and Cheniere has a non-investment grade corporate rating of B from Standard and Poor’s, indicating that Cheniere Marketing and Cheniere have a higher risk of being financially unable to perform on the Cheniere Marketing TUA than either Chevron or Total have 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 our LNG receiving terminal to support the payment of its obligations under its TUA, due to negative developments in the LNG industry or for other reasons, that risk 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 does not have unconditional agreements or arrangements for any supplies of LNG, for any vessels to transport LNG or for the utilization of capacity that it has contracted for under its TUA with us and may not be able to obtain such agreements or arrangements on economical terms, or at all;

• Cheniere Marketing does not have unconditional commitments from customers for the purchase of the natural gas it proposes to sell from our 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 our 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 our 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

• 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.

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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, which may include, vessels, pipelines and storage. Cheniere Marketing’s regasification capacity at our 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.

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

Our three TUAs provide for an in-kind deduction of 2% of the LNG delivered to our LNG receiving terminal, which we 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 we will have to purchase additional natural gas from third parties. We have 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 we may need to purchase for fuel.

Each of the three TUAs that we have entered into is subject to termination by the contractual counterparty under certain circumstances, and we are dependent on the performance of those counterparties under the TUAs.

We have 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 our LNG receiving terminal experiences aforce 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.” We 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, we are 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 we were to be ultimately successful in seeking damages from that counterparty or its guarantor for a breach of the TUA.

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, 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 our 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

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available from such terminals in the future. In addition, our 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. Our 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 that is currently under construction and 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 we have to replace our TUAs, and on our business, results of operations, financial condition and prospects.

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 and may cause us operating losses.

The economics of our LNG receiving 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 our 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., including from our LNG receiving terminal, to those markets;

• insufficient LNG production worldwide, which may limit the LNG imported into the U.S., including to our LNG receiving terminal;

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

• changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas, including the regasified LNG from our LNG receiving terminal; 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 pay our obligations on the notes.

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

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

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 payments on the notes.

The development of our LNG receiving terminal 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. LNG throughput volumes at our LNG receiving terminal would likely decline if the price of natural gas in North America is, or is forecasted 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 decrease their revenues and ability to make payments under the TUAs and result in a default of their payment obligations thereunder. Such payment defaults may have a material adverse effect on our business, results of operations, financial condition and prospects.

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 payments on the notes.

Commercial development of an LNG liquefaction facility can take a number of years and requires a very 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 liquefaction facility or LNG vessel.

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 our LNG receiving terminal to support their obligations under their TUAs.

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 payments on the notes.

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

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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;

• 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 payments on the notes.

In North America, due mainly to an historically abundant supply of natural gas, imported LNG has not been a major energy source in the past. 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 reduce our operating revenues, cause us operating losses and adversely affect our ability to make payments on the notes. In addition, other continents have a longer history of importing LNG and, due to their geographic proximity to LNG producers and limited domestic natural gas supplies, may be willing or able to pay more for LNG, thereby limiting the supply of LNG available in North American markets. 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.

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 we have to replace TUAs that terminate or expire.

Upon completion of our 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 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 our 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 our LNG receiving terminal, and the terminal and our customers do not have plans or equipment in place to condition such LNG to meet the pipeline specifications.

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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 our 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 our facility or damage to persons and property. In addition, our operations face possible risks associated with acts of aggression or terrorism on our facilities and the facilities and tankers of third parties on which our operations are dependent.

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

Existing and future governmental regulation could result in increased compliance costs or additional operating costs and restrictions.

Our business is and will be subject to extensive federal, state and local laws and regulations that 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, 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, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our LNG receiving terminal. Releases in violations of these regulations 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.

Existing environmental laws and regulations may be revised or reinterpreted or new laws and regulations may be adopted or become applicable to us. For example, the adoption of legislation and regulations to reduce “greenhouse gas emissions,” such as a carbon tax on energy sources that emit carbon dioxide into the atmosphere, may have a material adverse effect on the ability of our customers, particularly Cheniere Marketing: (i) to import LNG, if imposed on them as importers of potential emission sources, or (ii) to sell regasified LNG, if imposed on them or their customers as natural gas suppliers or consumers. In addition, as we consume retainage gas at our LNG receiving terminal, this carbon tax may also be imposed on us directly. Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to our LNG receiving terminal through the Sabine Pass Channel, could cause 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, our LNG receiving terminal. Due to our lack of asset and geographic diversification, an adverse development at our 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.

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Risks Relating to the Exchange Offer and the Notes

If you do not properly tender your initial notes, you will continue to hold unregistered outstanding notes and your ability to transfer outstanding notes will be adversely affected.

We will only issue notes in exchange for initial notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the initial notes, and you should carefully follow the instructions on how to tender your initial notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of initial notes. Please read “The Exchange Offer—Procedures for Tendering” and “Description of Notes.”

If you do not exchange your initial notes for notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your initial notes described in the legend on the certificates for your initial notes. In general, you may only offer or sell the initial notes if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. Except in connection with this exchange offer or as required by the registration rights agreement, we do not intend to register resales of the initial notes under the Securities Act. For further information regarding the consequences of tendering your initial notes in the exchange offer, please read “The Exchange Offer—Consequences of Failure to Exchange Outstanding Securities.”

Some holders who exchange their initial notes may be deemed to be underwriters.

If you exchange your initial notes in the exchange offer for the purpose of participating in a distribution of the notes, you may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

In addition to incurring indebtedness as a result of the notes, we will still be able to incur substantially more indebtedness in the future. This could further exacerbate the risks associated with our substantial leverage.

The indenture governing the notes does not prohibit us from incurring additional indebtedness, including additional senior or secured indebtedness, and other liabilities, or from pledging assets to secure such indebtedness and liabilities. The incurrence of additional indebtedness and, in particular, the granting of a security interest to secure the indebtedness could adversely affect our ability to pay our obligations on the notes.

Our substantial indebtedness could adversely affect our ability to operate our business and prevent us from fulfilling our obligations under the notes.

In connection with the issuance of the initial notes, we incurred $2,032 million of indebtedness, and, as of the date of this prospectus, we had no other indebtedness outstanding. Our substantial indebtedness could have important consequences including:

• making it more difficult for us to satisfy our obligations with respect to the notes;

• 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;

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• 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.

Our ability to satisfy our obligations, including the notes, 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 notes, on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.

To service our indebtedness, we will require significant amounts of cash. Our ability to generate cash will depend on many factors beyond our control.

We will require $151 million per year, commencing on May 30, 2007, to make interest payments on the notes. Our ability to make payments on and to refinance our indebtedness, including the notes, and to fund planned capital expenditures, will depend on our ability to generate cash in the future. Our business may not generate sufficient cash flow from operations, currently anticipated costs may increase or future borrowings may not be available to us in an amount sufficient to enable us to pay our indebtedness, including the notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the notes, on or before maturity. If any of the counterparties to our TUAs fails to perform its obligations under its respective TUA or if any of our TUAs are terminated, it could adversely affect our ability to make payments on or refinance the notes. We may not be able to refinance any of our indebtedness, including the notes, on commercially reasonable terms or at all.

Our financial estimates, including our illustrative cash flow summary, 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—Illustrative Cash Flow Summary,” 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 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 registered public accounting firm does 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.

In the preparation of its report attached to this prospectus as Appendix A, the Independent Engineer 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

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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, our business, financial condition, results of operations and prospects may be adversely affected.

The funds raised in connection with the offering of the initial notes may not be adequate to meet all of our needs, and we may have to seek additional financing.

As of March 31, 2007, we had spent $688.5 million toward the development and construction of our LNG receiving terminal. We expect to continue to make significant capital outlays for the foreseeable future to fund the remaining cost of our LNG receiving terminal prior to the time that we begin to generate positive cash flow from operations and for the foreseeable future thereafter. We currently believe that the net proceeds from the sale of the initial notes will be sufficient to meet our currently anticipated capital, operating and debt service requirements through the first half of 2009. We currently project that our cash flows from operations will commence in 2008, when Phase 1 of our LNG receiving terminal is anticipated to commence terminal operations, and will be sufficient to meet our ongoing capital and operating requirements and to pay the interest on our outstanding debt after the first half of 2009. Under its TUA, Cheniere Marketing may require us to build a sixth LNG storage tank within four years after notification from Cheniere Marketing, provided that, among other things, we can obtain financing we consider to be reasonably acceptable. This agreement could require us to incur substantial additional debt. If our cash flows from operations are less than projected, or if our future operating, capital and debt service requirements are higher than we currently estimate, we will require additional debt or equity financing in amounts that could be substantial.

The type, timing and terms of any future financing will depend on our cash requirements, our cash flows and prevailing conditions in the financial markets. Future financing may not be available to us at any given time or the terms thereof may not be desirable. Our current estimates of future results of operations (which will depend upon numerous future factors and conditions, many of which are outside of our control) may not be accurate. They are merely estimates of future events, and actual events will probably vary from current estimates, possibly materially. If we decide or are required to further expand our facility or to introduce new products or services, our funding needs will increase, possibly to a significant degree.

Because the costs of constructing, maintaining and operating our LNG receiving terminal, the costs of conducting our business, and the amounts of our future revenues, will all depend on a variety of factors (including our ability to meet our construction schedules, performance by our contract counterparties and potential regulatory changes), actual costs and revenues may vary from expected amounts, possibly to a material degree, and such variations are likely to affect our future capital requirements. Accordingly, we may be required to raise substantial additional capital in the future and our current estimates may prove to be inaccurate.

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

The indenture governing the notes contains several significant covenants that, among other things, restrict our ability to:

• incur additional indebtedness;

• create liens on our assets; and

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

Under some circumstances, these restrictive covenants may not allow us the flexibility that we need to operate our business in an effective and efficient manner and may prevent us from taking advantage of strategic and financial opportunities that would benefit our business. However, these covenants are also subject to significant exceptions which provide flexibility to us but may provide greater risk to holders of the notes.

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

We may not be able to repurchase the notes upon a change in control or upon the exercise of the holders’ options to require repurchase of notes if certain asset sales or loss events occur.

Upon the occurrence of a change in control, you will have the right to require us to repurchase your notes at a purchase price in cash equal to 101% of the principal amount of your notes plus accrued and unpaid interest, if any. Any future credit agreement or other agreements relating to indebtedness to which we become a party may contain similar provisions. In the event that we or our general partner experiences a change in control that results in us having to repurchase the notes or upon the exercise of the holders’ options to require repurchase of the notes in the event of certain asset sales or loss events, we may not have sufficient financial resources to satisfy all of our obligations under the notes and our other debt instruments. Our failure to make the change in control offer or to pay the change in control purchase price when due or to make payments upon the exercise of the holders’ options to require repurchase of the notes in the event of certain asset sales or loss events would result in a default under the indenture governing the notes. In addition, the change in control feature of the notes does not cover all corporate reorganizations, mergers or similar transactions and may not provide you with protection in a highly leveraged transaction. See “Description of Notes—Repurchase at the Option of Holders.”

Federal and state statutes allow courts, under specific circumstances, to void the notes and require note holders to return payments received from us.

Under the federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, the notes could be voided, or claims in respect of the notes could be subordinated to all other debts of ours if, among other things, we, at the time the indebtedness evidenced by the notes was incurred:

• received less than reasonably equivalent value or fair consideration for the incurrence of the indebtedness; and

• were insolvent or rendered insolvent by reason of the incurrence of the indebtedness; or

• were engaged, or about to engage, in a business or transaction for which our remaining assets constituted unreasonably small capital; or

• intended to incur, or believed that we would incur, debts beyond our ability to pay such debts as they matured.

In addition, any payment by us could be voided and required to be returned to us, or to a fund for the benefit of our creditors. In any such case, your right to receive payments in respect of the notes from us would be effectively subordinated to all of our indebtedness and other liabilities.

The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, we would be considered insolvent if:

• the sum of our debts, including contingent liabilities, was greater than the fair saleable value of all of our assets;

• if the present fair saleable value of our assets were less than the amount that would be required to pay our probable liability on our total existing debts and liabilities, including contingent liabilities, as they become absolute and mature; or

• we could not pay our debts as they become due.

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The rights of the collateral trustee to foreclose upon collateral may be impaired by bankruptcy law.

The rights of the collateral trustee under the security documents to foreclose upon and sell collateral, including assets in any reserve account, upon the occurrence of an event of default on the notes is likely to be significantly impaired by applicable bankruptcy law if a bankruptcy or reorganization case were to be commenced by or against us. Under applicable bankruptcy law, secured creditors such as the holders of the notes would be prohibited from foreclosing upon or disposing of a debtor’s property without prior bankruptcy court approval.

Your ability to resell the notes may be limited by a number of factors; prices for the notes may be volatile.

The notes will not be listed on any securities exchange or on any automated dealer quotation system. An active market may not exist for the notes; any trading market that does develop may not be liquid. If a market for the notes were to develop, the notes could trade at prices that may be higher or lower than reflected by their initial offering price, depending on many factors, including among other things:

• changes in the overall market for debt securities;

• changes in our financial performance or prospects;

• the prospects for companies in our industry generally;

• the number of holders of the notes;

• the interest of securities dealers in making a market for the notes; and

• prevailing interest rates.

In addition, the market for non-investment grade indebtedness has historically been subject to disruptions that have caused substantial volatility in the prices of securities similar to the notes. The market for the notes, if any, may be subject to similar disruptions. Any such disruption could adversely affect the value of your notes.

The forward-looking statements contained in this prospectus are based on our predictions of future performance. As a result, you should not place undue reliance on these forward-looking statements.

This prospectus includes forward-looking statements, which are statements other than statements of historical fact and include, in particular the statements about our plans, strategies, and prospects under the headings “Summary,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business.” Our plans, intentions or expectations included in this prospectus may not be achieved. Important factors that could cause actual results to differ materially from the forward-looking statements we make in this prospectus are set forth above in this “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements.

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USE OF PROCEEDS

We will not receive any proceeds from the issuance of the notes in the exchange offer. The exchange offer is intended to satisfy our obligations under the registration rights agreement we entered into in connection with the private offering of the initial notes. In consideration for issuing the notes as contemplated in this prospectus, we will receive, in exchange, outstanding initial notes in like principal amount. We will cancel all initial notes surrendered in exchange for notes in the exchange offer. As a result, the issuance of the notes will not result in any increase or decrease in our indebtedness.

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SELECTED HISTORICAL FINANCIAL DATA

The following tables set forth our selected financial data for the periods and at the dates indicated. The summary statement of operations data for the years ended December 31, 2004, 2005 and 2006, and the balance sheet information at December 31, 2005 and 2006 are derived from our audited financial statements, which are included elsewhere in this prospectus. The summary statement of operations data for the three months ended March 31, 2007 and 2006 and the balance sheet information at March 31, 2007 are derived from our unaudited financial statements, which are included elsewhere in this prospectus. The summary statement of operations data for the period from October 20, 2003 (inception) through December 31, 2003 and the summary balance sheet information at December 31, 2003 and 2004 have been derived from our audited financial statements, which are not included in this prospectus. 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 tables from, and that information should be read together with and is qualified in its entirety by reference to, the 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.”

(Dollars in thousands)	Period from October 20, 2003 (inception) to December 31, 2003			Year ended December 31,									Three Months Ended March 31,
				2004			2005			2006			2007			2006
Revenues	$	—		$	—		$	—		$	—		$	—		$	—
Expenses		2,763			4,682			4,711			10,265			1,860			1,590
Loss from operations		(2,763	)		(4,682	)		(4,711	)		(10,265	)		(1,860	)		(1,590	)
Other income (expense)(1)		—			28			456			(50,495	)		(11,050	)		810
Net loss	$	(2,763	)	$	(4,654	)	$	(4,255	)	$	(60,760	)	$	(12,910	)	$	(780	)
Ratio of earnings to fixed charges(2)		—			—			—			—			—			—

(Dollars in thousands)	December 31,								March 31, 2007
	2003		2004		2005		2006
Cash and cash equivalents (unrestricted)	$	—	$	21,822	$	—	$	—	$	—
Non-current restricted cash and cash equivalents		—		—		—		982,613		882,919
Restricted cash and cash equivalents		—		—		8,871		176,324		209,645
Total assets		101		23,316		309,135		1,858,111		1,915,487
Long-term debt		—		—		37,377		2,032,000		2,032,000
Deferred revenues		—		22,000		40,000		40,000		40,000
Total other long-term liabilities		2,864		17,418		120		1,149		1,154

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

(2) The ratios were computed by dividing earnings by fixed charges. For this purpose, “earnings” represent the aggregate of (a) pre-tax income from continuing operations before adjustment for minority interests in consolidated subsidiaries or income or loss from equity investees, (b) fixed charges, (c) amortization of capitalized interest, (d) distributed income of equity investees and (e) our share of pre-tax losses of equity investees for which charges arising from guarantees are included in fixed charges, net of (a) interest capitalized and (b) the minority interest in pre-tax income of subsidiaries that have not incurred fixed charges. “Fixed charges” represent the sum of (a) interest expensed and capitalized, (b) amortized premiums, discounts and capitalized expenses related to indebtedness and (c) an estimate of the interest within rental expense. As a result of reported losses, earnings were inadequate to cover fixed charges, thereby resulting in a coverage deficiency of $2.8 million for the period from October 20, 2003 (inception) to December 31, 2003, $4.7 million, $9.7 million and $83.1 million for the years ended December 31, 2004, 2005 and 2006, respectively, and $25.8 million and $3.5 million for the three months ended March 31, 2007 and 2006, respectively.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of financial condition and results of operations should be read in conjunction with our historical financial statements included in this prospectus. The following discussion contains, in addition to historical information, forward-looking statements that are subject to significant risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including those factors set forth under the captions “Forward-Looking Statements” and “Risk Factors” and elsewhere in this prospectus.

BUSINESS AND OPERATIONS

In 2003, we were formed by Cheniere to own, develop and operate the Sabine Pass LNG receiving terminal. The initial phase, or Phase 1, of our 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 billion cubic feet, or Bcf, along with two unloading docks capable of handling the largest LNG carriers currently being operated or built. In July 2006, we received approval from the FERC to increase the regasification capacity of our LNG receiving terminal up to 4.0 Bcf/d and to add up to three additional LNG storage tanks and related facilities. This expansion is referred to as Phase 2.

Although we are still in the process of constructing our LNG receiving terminal, we have already entered into three TUAs, through which Total, Chevron and Cheniere Marketing have reserved an aggregate of the entire 4.0 Bcf/d of LNG regasification capacity that will be available upon completion of Phase 1 and Phase 2 – Stage 1 of our LNG receiving terminal. Payment obligations under the Total, Chevron and Cheniere Marketing TUAs have been guaranteed by Total, S.A., Chevron Corporation and Cheniere, respectively.

Construction of our LNG receiving terminal began in March 2005. We expect to achieve Phase 1 Target Completion during the second quarter of 2008. We expect to complete construction and commissioning of the third tank and the rest of Phase 1, and achieve the full 2.6 Bcf/d of Phase 1 regasification capacity, in the third quarter of 2008. LNG regasification operations relating to the Phase 2 – Stage 1 expansion are expected to commence by April 2009. We expect to complete all of Phase 2 – Stage 1, including construction and commissioning of the fourth and fifth tanks, and achieve full operability at 4.0 Bcf/d in the third quarter of 2009.

LIQUIDITY AND CAPITAL RESOURCES

General

Our LNG receiving terminal project will require significant amounts of capital and is subject to risks and delays in completion. Even if successfully completed, our LNG receiving terminal is not expected to begin to operate and generate significant cash flows before the second quarter of 2008, at the earliest.

The cost to construct Phase 1 of our LNG facility is currently estimated at approximately $900 million to $950 million, before financing costs. Phase 2 – Stage 1 is estimated to cost approximately $500 million to $550 million, 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 currently expect that our capital resources requirements will be financed through the proceeds received from the issuance of the initial notes and cash flows under our three TUAs. We believe that we have adequate financial resources to complete Phase 1 and Phase 2 – Stage 1 of our LNG receiving terminal and to meet our anticipated operating, maintenance and debt service requirements through the first half of 2009. Furthermore, we anticipate that:

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

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• beginning in the third quarter of 2009, cash flows from operations will be sufficient to cover all debt service on the notes and all of our other operating costs.

To service our indebtedness, we will require significant amounts of cash. 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 pay our indebtedness, including the notes, or to fund our other liquidity needs, including operating expenses. 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.

Capital Resources

Proceeds from Issuance of Initial Notes

We received approximately $2 billion in net proceeds from the issuance of the initial notes. We placed $335 million of the net proceeds in a reserve account to fund scheduled interest payments on the 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 our 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 initial notes to repay indebtedness, to make a distribution to Cheniere LNG Holdings, LLC for the repayment of its outstanding term loan and to pay fees and expenses related to the issuance of the initial notes.

Customer TUAs

Each of our customers must make payments under its TUA 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 our LNG receiving terminal has achieved commercial operation at 2.0 Bcf/d, which we expect will occur during the second quarter of 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, subject to certain exceptions.

• 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.

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Uses of Capital

Phase 1 EPC Agreement

In December 2004, we entered into a lump-sum turnkey EPC agreement with Bechtel for Phase 1 of our 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 our LNG receiving terminal in accordance with the requirements of the EPC agreement.

Pursuant to the EPC agreement, we 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 April 30, 2007, change orders for $132.3 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 $779.2 million.

Phase 2 Construction Agreements

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

We entered into an engineering, procurement, construction and management, or EPCM, agreement with Bechtel pursuant to which Bechtel will provide: design and engineering services for Phase 2 – Stage 1 of our LNG receiving terminal project, except for such portions to be designed by other contractors and suppliers that we contract 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 our sole discretion upon completion of Phase 2 – Stage 1. See “Description of Principal Project Documents—Phase 2 – Stage 1 EPCM Agreement.”

We entered into an EPC LNG tank contract with Zachry Construction Corporation, or Zachry, and Diamond LNG LLC, or Diamond, pursuant to 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. 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. See “Description of Principal Project Documents—Phase 2 – Stage 1 EPC LNG Tank Contract.”

We entered into an EPC LNG unit rate 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 otherwise set forth in the soil contract. Upon issuing a final notice to proceed in August 2006, we 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. See “Description of Principal Project Documents—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, we 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

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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. If Cheniere Marketing exercises its option, we will have to negotiate one or more new construction agreements with one or more new contractors. We will not receive additional revenues in exchange for constructing a sixth LNG storage tank under the Cheniere Marketing TUA.

Services Agreements

Operation and Maintenance Agreement. In February 2005, we 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 our 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, we are 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 us and O&M Services at the beginning of each operating year. In addition, we are required to reimburse O&M Services for our operating expenses, which consist of labor, maintenance, land lease and insurance expenses, and for maintenance capital expenditures.

In March 2007, O&M Services assigned the O&M Agreement to Cheniere Energy Partners GP, LLC, or Cheniere Energy Partners GP, and O&M Services and Cheniere Energy Partners GP entered into a services and secondment agreement pursuant to which certain employees of O&M Services have been seconded to Cheniere Energy Partners GP to provide operating and routine maintenance services with respect to our LNG receiving terminal under the direction, supervision and control of Cheniere Energy Partners GP. Under this agreement, Cheniere Energy Partners GP will pay O&M Services the amounts that it receives from us under the O&M Agreement. The services and secondment agreement will remain in effect until the O&M Agreement is terminated; however, Cheniere Energy Partners GP may terminate the agreement upon 30 days written notice.

Management Services Agreement. In February 2005, we entered into a Management Services Agreement, or the Sabine Pass LNG MSA, with our general partner, Sabine Pass LNG-GP, Inc. Pursuant to the Sabine Pass LNG MSA, we appointed our general partner to manage the construction and operation of our 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 our LNG receiving terminal, we are required to pay our 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).

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

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

Maintenance Capital Expenditures

Beginning in 2009, we expect to incur approximately $1.5 million per year in maintenance capital expenditures, which are generally capital expenditures to maintain the operating capacity or asset base of our LNG receiving terminal and extend its useful life.

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State Tax Sharing Agreement

In November 2006, we 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 we are required to file on a combined basis and to timely pay the combined tax liability. If Cheniere, in its sole discretion, demands payment, we will pay to Cheniere an amount equal to the Texas franchise tax that we would be required to pay if our Texas franchise tax liability were computed on a separate company basis. This agreement contains similar provisions for other state and local taxes that we and Cheniere 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—Arrangements Regarding Taxes.”

Senior Secured Notes

In November 2006, we 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 “Description of Notes.”

Historical Cash Flows

Three Months Ended March 31, 2007 compared to Three Months Ended March 31, 2006

The following table summarizes the changes in our cash and cash equivalents for the three months ended March 31, 2007 and 2006. Additional discussion of the key elements contributing to these changes follow the table (in thousands).

	For the Three Months Ended March 31,
	2007			2006
Cash provided by (used in):
Operating activities	$	(313	)	$	(3,219	)
Investing activities		947			(62,019	)
Financing activities		(634	)		65,238
Net increase (decrease) in cash and cash equivalents	$	—		$	—
Cash and cash equivalents at end of year	$	—		$	—

Operating Activities—Net cash used in operating activities was $0.3 million during the three months ended March 31, 2007 compared to net cash used in operating activities of $3.2 million in the same period of 2006. The lack of cash generated from operating activities is the direct result of the continued development of our LNG receiving terminal business. Operations to date have been devoted to pre-construction and construction activities.

Investing Activities—Net cash provided by investing activities was $0.9 million during the three months ended March 31, 2007 compared to net cash used in investing activities of $62.0 million during the same period of 2006. During the first three months of 2007, we invested $73.0 million in constructing our LNG receiving terminal and $6.6 million in advances under long-term contracts relating to our LNG receiving terminal, which was funded by the use of $81.5 million of restricted cash and cash equivalents. During the first three months of 2006, we invested $78.5 million in our LNG receiving terminal for construction costs.

Financing Activates—Net cash used in financing activities during the three months ended March 31, 2007 was $0.6 million compared to net cash provided by financing activities of $65.2 million during the same period in 2006. During the first three months of 2007, we paid $0.6 million of debt issuance costs. During the first three months of 2006, we received $70.0 million of proceeds from borrowings under our credit facility, which was subsequently terminated in connection with the issuance of the initial notes.

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Our cash and cash equivalent ending balances were zero as of March 31, 2007 and March 31, 2006 , as all cash and cash equivalents were restricted under the terms of the indenture governing the initial notes and the amended credit facility.

Fiscal Year Ended December 31, 2006 compared to Fiscal Years Ended December 31, 2005 and 2004

The following table summarizes the changes in our cash and cash equivalents for the years ended December 31, 2006, 2005 and 2004. Additional discussion of the key elements contributing to these changes follow the table (in thousands).

	Years Ended December 31,
	2006			2005			2004
Cash provided by (used in):
Operating activities	$	(27,901	)	$	6,327		$	23,192
Investing activities		(1,544,408	)		(246,337	)		(124	)
Financing activities		1,572,309			218,188			(1,246	)
Net increase (decrease) in cash and cash equivalents	$	—		$	(21,822	)	$	21,822
Cash and cash equivalents at end of year	$	—		$	—		$	21,822

Operating Activities—Net cash used in operating activities was $27.9 million during 2006 compared to $6.3 million net cash provided by operating activities in 2005. Net cash used in operating activities during 2006 was primarily the result of the $20.6 million derivative loss incurred upon the termination of interest rate swaps related to the termination of the amended credit facility. Absent this derivative loss, we would have recorded net cash used in operating activities of $7.3 million for 2006. Net cash provided by operating activities during 2005 was primarily the result of our receipt of $18.0 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 $4.3 million for 2005. Net cash provided by operating activities during 2004 was primarily the result of our receipt of $22.0 million in advance terminal capacity reservation fees.

Investing Activities—Net cash used in investing activities was $1.5 billion during 2006 compared to net cash used in investing activities of $246.3 million during 2005. During 2006, we funded $1.2 billion related to restricted cash balances as required to be funded by the indenture governing the initial notes and we recorded $387.7 million to construction-in-progress related to our LNG receiving terminal. Our investment activities during 2005 included $229.1 million recorded to construction-in-progress related to our LNG receiving terminal, $8.9 million related to the funding of restricted cash balances, and $8.1 million of advances to our EPC contractor.

Financing Activates—Net cash provided by financing activities during 2006 was $1.6 billion compared to net cash provided by financing activities of $218.2 million in 2005. During 2006, we received proceeds from borrowings under the amended credit facility and issuance of the initial notes totaling $383.4 million and $2.0 billion, respectively. These proceeds were partially offset by repayments of the amended credit facility of $383.4 million and a subordinated note to an affiliate of $37.4 million. We also paid debt issuance costs during 2006 of $44.0 million as a result of amending our credit facility and the issuance of the initial notes, and we made a $378.3 million distribution to our limited partner. During 2005, we received $196.7 million in limited partner capital contributions from an affiliate, $37.4 million in proceeds from a subordinated note with an affiliate, which were partially reduced by $15.8 million in debt issuance costs related to the original credit facility.

Our cash and cash equivalent ending balances were zero as of December 31, 2006 and 2005, as all cash and cash equivalents were restricted under the terms of the indenture governing the initial notes and the amended credit facility.

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Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts. We have no off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed the debt of any other party. The following table summarizes certain contractual obligations in place as of December 31, 2006 (in thousands).

	Payments Due for Years Ended December 31,
	Total		2007		2008-2009		2010-2011		Thereafter
Operating lease obligations—
LNG site rental(1)	$	132,104	$	1,507	$	3,012	$	3,002	$	124,583
Long-term debt(2)		2,032,000		—		—		—		2,032,000
Service contracts—
Affiliate O&M agreement(1)		33,480		1,140		2,700		3,120		26,520
Affiliate Sabine Pass LNG MSA(1)		134,320		4,080		9,600		12,480		108,160
Construction and purchase obligations(1)(3)		706,092		405,469		300,623		—		—
Total	$	3,037,996	$	412,196	$	315,935	$	18,602	$	2,291,263

(1) A discussion of these obligations can be found in Note 14 to our Audited Financial Statements.

(2) A discussion of these obligations can be found in Note 11 to our Audited Financial Statements and in the section titled “Description of Notes”.

(3) Represents construction contracts and obligations to purchase long lead equipment and materials for our LNG receiving terminal.

LNG Receiving Terminal Construction Contracts

As more fully described in Note 14 to our Audited Financial Statements, we have entered into construction contracts with various third parties to construct Phase 1 and Phase 2 – Stage 1 of our LNG receiving terminal. We estimate that the cost to construct Phase 1 and Phase 2 – Stage 1 of our LNG receiving terminal will be approximately $1.4 billion to $1.5 billion, before financing costs.

Inflation

We have experienced escalating steel prices relating to the construction of our 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 our LNG receiving terminal.

RESULTS OF OPERATIONS

Three Months Ended March 31, 2007 compared to Three Months Ended March 31, 2006

Overview

Our financial results for the three months ended March 31, 2007 reflected a net loss of $12.9 million, compared to a net loss of $0.8 million in the same period in 2006. Because we are a development stage company and our operations consist solely of constructing our LNG receiving terminal, we have not generated any operating revenues since inception.

Expenses

Total expenses increased $0.3 million, or 19%, to $1.9 million for the three months ended March 31, 2007 compared to $1.6 million in the same period in 2006. This increase was primarily attributable to the increase in labor charges from an affiliate. During the first three months of 2007, certain employee charges were charged to us under our services agreements. Such charges are not subject to capitalization.

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Other Income (Expense)

Total other expense for the three months ended March 31, 2007 was $11.1 million compared to other income of $0.8 million in the same period in 2006. The increase in other expense related to an increase in interest expense partially offset by an increase in interest income. Interest expense increased due to our average debt balance being much larger in the first three months of 2007 compared to the first three months of 2006 as a result of the initial notes being outstanding, during which time the interest expense exceeded the amount of interest capitalized. In the first three months of 2006, all of our interest expense incurred under our credit facility, in place at that time, was capitalized. Interest income increased in the first three months of 2007 compared to the first three months of 2006 due to a much higher cash and cash equivalent average balance during the first three months of 2007 compared to a nominal cash and cash equivalent average balance in the same period of 2006.

Fiscal Year Ended December 31, 2006 compared to Fiscal Year Ended December 31, 2005

Overview

Our financial results for the year ended December 31, 2006 reflected a net loss of $60.8 million, compared to a net loss of $4.3 million in 2005. Because we are a development stage company and our operations consist solely of constructing our LNG receiving terminal, we have not generated any operating revenues since inception.

Expenses

Total expenses increased $5.6 million, or 119.1%, to $10.3 million in 2006 compared to $4.7 million in 2005. This increase was primarily attributable to the reimbursement of development expenses related to Phase 2 – Stage 1 of our LNG receiving terminal and land site rental costs.

Prior to the execution of the amended 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 our LNG receiving terminal and other required permitting. Concurrently with the execution of the amended credit facility in July 2006, such development 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 our LNG receiving terminal; however, beginning in January 2006, these rental payments ($1.5 million per year) are expensed as required by FSP FAS No. 13-1,Accounting for Rental Costs Incurred during a Construction Period.

Other Income (Expense)

Total other expense, net of interest income, for the year ended December 31, 2006 was $50.5 million compared to other income of $0.5 million in 2005. In connection with the issuance of the initial notes in November 2006, we terminated the amended credit facility. As a result, we recorded a $23.8 million non-cash loss on the early extinguishment of debt related to debt issuance costs and a $20.6 million derivative loss primarily as a result of terminating related interest rate swaps. In 2006, we also recorded interest expense of $15.5 million, net of $22.3 million capitalized interest. These expenses were partially offset by interest income in 2006 of $9.3 million as a result of the increase in restricted cash from the issuance of the initial notes.

Other income for the year ended December 31, 2005 was $0.5 million. We recorded a derivative gain of $0.3 million in 2005 related to the ineffective portion of our interest rate swap gain associated with the original credit facility entered into in February 2005.

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.

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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 our LNG receiving terminal and other required permitting. In March 2005, we received the order from FERC authorizing construction of our LNG receiving terminal and other required permitting and, accordingly, began construction. In mid-February 2005, we began paying overhead charges to affiliates related to services required to construct our 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 $28,000 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 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 our LNG receiving terminal and other required permitting.

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 our 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.

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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. We assess, both at the inception of each hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. On an on-going basis, we monitor the actual dollar offset of the hedges’ market values compared to hypothetical cash flow hedges. Any ineffective portion will be reflected in earnings. Ineffectiveness is the amount of gains or losses from derivative instruments that are not offset by corresponding and opposite gains or losses on the expected future transactions.

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 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 believe that the adoption of SFAS No. 156 will not have a material impact on our financial position, results of operations or cash flows.

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

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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. We adopted FIN No. 48 in the first quarter of 2007. The adoption of FIN No. 48 had no 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 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.

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BUSINESS

Overview

We are an indirect subsidiary of Cheniere Energy, Inc., or Cheniere, which owns a 90.6% interest in us, created to develop, own and operate the Sabine Pass liquefied natural gas, or LNG, receiving terminal currently under construction in western Cameron Parish, Louisiana on the Sabine Pass Channel. The entire 4.0 billion cubic feet per day, or Bcf/d, of regasification capacity that will be available at our LNG receiving terminal upon completion of construction has been fully reserved under three 20-year terminal use agreements, or TUAs, under which the customers are generally required to pay fixed monthly fees, whether or not they use the terminal. Provided our LNG receiving terminal has achieved the required level of commercial operation, which we expect will occur in the third quarter of 2008, these 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;

• 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 for 20 years commencing not later than July 1, 2009; and

• 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 commencing on the date of commercial operations completion.

Industry Overview

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. Natural gas has an advantage over other primary energy sources such as oil and coal because it is clean burning and therefore more environmentally friendly. North America’s energy requirements will continue to increase.

Substantial natural gas reserves are located in countries that have low energy consumption and are far from major energy demand centers. Natural gas reserves located 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. LNG is therefore becoming an increasingly significant alternative for distributing natural gas produced in remote areas to key centers of natural gas consumption. According to the Groupe International des Importateurs de Gaz Naturel Liquifie, or GIIGNL, as of December 31, 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 40% during the 2000 to 2005 period. Liquefaction capacity will reach approximately 37 Bcf/d in 2010, according to Wood Mackenzie Limited.

Although LNG has been used commercially in the U.S. since the 1940s, its role was limited to meeting demand peaks caused by seasonal variations. Historically, abundant supplies of domestically sourced, low-cost, piped natural gas kept pace with demand, making the need for LNG imports minimal and sporadic. However, the average wellhead price of natural gas produced in the U.S. has more than doubled in the last five years, indicating a maturing domestic resource base and supporting the economic viability of marginal drilling and imports of LNG.

As of January 18, 2007, there were five operational onshore LNG regasification facilities in continental North America with an aggregate send out capacity of 4.75 Bcf/d and the capability to satisfy approximately 6%

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of natural gas consumption in North America. LNG imports to the U.S. reached 619 Bcf in 2005. LNG is expected to play a more pivotal role in satisfying North American natural gas demand as additional receiving capacity becomes available.

Imports can only increase significantly if new LNG receiving capacity is constructed. Former Chairman of the Federal Reserve, Alan Greenspan, stated 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.”

Business Strategies

Our primary business objective is to generate stable cash flows by:

• completing construction and commencing operation of our LNG receiving terminal;

• applying proven, conventional technology to mitigate development and operating risk, while utilizing advanced control and safety technology; and

• maintaining the effectiveness of long-term TUAs to generate steady and reliable revenues.

Strengths

We believe that we have several strengths in pursuing our business strategy:

Contracted and Stable Long-Term Cash Flows. All of the regasification capacity that will be available at our 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 us 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 us 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 notes, which will be approximately $151 million; and

• all of our other annual operating costs, which we estimate will be approximately $48 million for the four consecutive quarters ending June 30, 2010.

• No Direct LNG Supply Risk or Direct Commodity Price Risk under the TUAs. Our customers, rather than our partnership, bear all direct risks associated with obtaining supplies of LNG, transporting LNG to our 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 that we are entitled to receive from our 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 our customers.

• Long-term Commitments. Under the TUAs, our customers have committed to make monthly payments for 20-year terms. Our customers have options to extend their TUAs for one or more additional 10-year terms. Our customers are able to terminate their TUAs before 20 years only in limited circumstances, such as aforce 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 aforce majeure event.

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Solid Construction Arrangements. 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. We believe these provisions mitigate the potential for delays. In addition, we have fixed the costs for a substantial majority of the materials used to construct our LNG receiving terminal, which minimizes the risk posed by escalation of those prices.

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 our LNG receiving terminal. Located at the Texas/Louisiana border only 3.7 miles from open waters near the Gulf of Mexico, our LNG receiving terminal site is easily accessible by the largest LNG transport vessels currently operating or being built. Our LNG receiving terminal is located in close proximity to interconnection points with numerous existing natural gas pipelines.

Ample Pipeline Access. We anticipate that our 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 our 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 our 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, our 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 our LNG receiving terminal will benefit from economies of scale in operating expenses. After completing Phase 1, we expect that the annual operating expenses of our 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 our LNG receiving terminal. We consider investing time and effort into developing strong community relationships a key factor in ensuring the success of our LNG receiving terminal. We began the application process for our LNG receiving terminal only after we were convinced that the local community understood the process and was willing to support our 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 our 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.

Comprehensive Collateral Package. The notes benefit from a comprehensive collateral package, including a first-priority lien on substantially all of our assets, including our rights under the TUAs. While all Phase 2 – Stage 1 assets will form an integral part of the collateral package, the Total and Chevron TUAs do not rely on Phase 2 – Stage 1 capacity, and Phase 2 – Stage 1 construction has been structured to avoid potential interruption of the construction of Phase 1.

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Availability of Reserves. The availability of reserve funds offers multiple sources of liquidity. A construction debt service reserve will fund the first five semi-annual interest payments, which will cover the anticipated construction period for Phase 1 and will be replaced by a permanent six-month debt service reserve to be funded with cash flow from operations. In addition, a debt payment reserve will be funded with monthly deposits of cash flow from operations and used to pay regular semiannual interest payments. See “Description of Notes—Project Accounts.”

LNG Receiving Terminal Development

In 2003, we were formed by Cheniere to own, develop and operate our LNG receiving terminal in western Cameron Parish, Louisiana, on the Sabine Pass Channel. We have entered into leases for three tracts of land comprising 853 acres in Cameron Parish, Louisiana for the project site. Phase 1 of our LNG receiving terminal was designed, and permitted by the FERC, 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 and two unloading docks capable of handling the largest LNG carriers currently being operated or built. In July 2006, we received FERC approval to increase the regasification capacity of our 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. This expansion is referred to as Phase 2.

Phase 1

In March 2005, the FERC issued an order authorizing us to commence construction of Phase 1 of our LNG receiving terminal, subject to certain ongoing conditions. Construction of our LNG receiving terminal began in March 2005. We expect to achieve Phase 1 Target Completion by the second quarter of 2008. We expect to complete construction and commissioning of the third tank and the rest of Phase 1, and achieve the full 2.6 Bcf/d of Phase 1 regasification capacity, during the third quarter of 2008.

The cost to construct Phase 1 of our LNG receiving terminal is currently estimated to be approximately $900 million to $950 million, before financing costs, but including the change orders discussed below. In December 2004, we entered into a lump-sum turnkey agreement with Bechtel, a major international EPC contractor, which currently requires us to pay Bechtel $779.2 million, including change orders agreed through April 30, 2007. Our 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 our construction schedules.

In August 2005, construction at Phase 1 of our LNG receiving terminal site was temporarily suspended in connection with Hurricane Katrina, as a precautionary measure. In September 2005, the terminal site was again secured and evacuated in anticipation of Hurricane Rita. Construction activities were remobilized at the site and returned to pre-hurricane levels by mid-November 2005. While no significant damage occurred to the site, equipment or materials at our LNG receiving facility, as a residual effect of the hurricanes, 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, we agreed to change orders with Bechtel concerning additional activities and expenditures to mitigate the hurricanes’ effects on the completion of Phase 1 of our LNG receiving terminal. See “Description of Principal Project Documents—Phase 1 EPC Agreement—Force Majeure.”

Phase 2

In July 2006, we received authorization from the FERC to commence site preparation construction activities for the Phase 2 expansion of our LNG receiving terminal, subject to certain ongoing conditions. The first stage of the Phase 2 expansion will include the addition of a fourth and fifth LNG storage tank, additional vaporizers and related facilities, thereby increasing the total regasification capacity of our LNG receiving terminal to 4.0 Bcf/d. This expansion is referred to as Phase 2 – Stage 1. LNG regasification operations relating to the Phase 2 –

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Stage 1 expansion are expected to commence before April 2009. We expect to complete all of Phase 2 – Stage 1, including construction and commissioning of the fourth and fifth tanks, and to achieve full operability at 4.0 Bcf/d and aggregate storage capacity of approximately 16.8 Bcf during the third quarter of 2009.

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

We entered into an EPCM agreement with Bechtel pursuant to which Bechtel will provide: design and engineering services for Phase 2 – Stage 1 of our LNG receiving terminal project, except for such portions to be designed by other contractors and suppliers that we contract 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 our sole discretion upon completion of Phase 2 – Stage 1. See “Description of Principal Project Documents—Phase 2 – Stage 1 EPCM Agreement.”

We entered into an EPC LNG tank contract with Zachry and Diamond pursuant to 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 and construct the two Phase 2 – Stage 1 LNG storage tanks. 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. See “Description of Principal Project Documents—Phase 2 – Stage 1 EPC LNG Tank Contract.”

We entered into an EPC LNG unit rate soil contract with 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 otherwise set forth in the soil contract. Upon issuing a final notice to proceed in August 2006, we 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. See “Description of Principal Project Documents—Phase 2 – Stage 1 EPC LNG Soil Contract.”

Phase 2 – Stage 1 is estimated to cost approximately $500 million to $550 million, before financing costs. Operations relating to the Phase 2 – Stage 1 expansion are expected to commence before April 2009, and all of Phase 2 – Stage 1 is expected to be completed during the third quarter of 2009.

Customers

We have entered into three TUAs, through which Total, Chevron and Cheniere Marketing have reserved, in the aggregate, the entire approximately 4.0 Bcf/d of LNG regasification capacity that will be available upon completion of Phase 1 and Phase 2 – Stage 1 of our LNG receiving terminal. The Total TUA and the Chevron TUA reserve a combined annual LNG regasification capacity of approximately 2.0 Bcf/d. Phase 1 of our LNG receiving terminal (2.6 Bcf/d) will be sufficient to cover our obligations under the Total and Chevron TUAs. Cheniere Marketing has reserved the entire 2.0 Bcf/d of capacity that will be available beyond the Total and Chevron TUA capacity reservations, upon completion of Phase 2 – Stage 1, as well as any Phase 1 capacity that is available prior to the commencement of the Total and Chevron TUAs and after we have fulfilled our obligations under the Total and Chevron TUAs.

Total TUA

In September 2004, we entered into a TUA with Total to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at our LNG receiving terminal. We have no obligation to provide

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Total with certain services such as (i) harbor, mooring and escort services for LNG vessels, including the provision of tugboats, (ii) the transportation of natural gas downstream from our LNG receiving terminal or the construction of any pipelines to provide such transportation or (iii) the marketing of natural gas.

Under the TUA, Total has reserved 390,915,000 million British thermal units, or MMBtu, of annual LNG receipt capacity, which is equivalent to approximately 1.0 Bcf/d of regasification capacity, assuming an energy content of 1.05 MMBtu per thousand cubic feet, or Mcf, and retainage of 2%. Total’s fees under the TUA are payable monthly in advance, commencing with the commercial start date of April 1, 2009 (subject to achieving commercial operations completion by that date, and subject to delay by events offorce majeure) and will continue for a term of 20 years subject to six additional 10-year extension terms. Commercial operations completion will be achieved when our LNG receiving terminal is ready to be used for its intended purpose to provide the services called for under the Total TUA, with Bechtel as contractor for the Phase 1 EPC agreement having achieved all minimum acceptance requirements under the Phase 1 EPC agreement sufficient to provide the services called for under the Total TUA and contracts with other customers purchasing LNG terminalling services from us similar to the services called for under the Total TUA. Under the Total TUA, Total will pay a monthly fixed capacity reservation fee of $9.1 million; a monthly operating fee of $1.3 million, which is adjusted annually for changes in the U.S. Consumer Price Index (All Urban Consumers); and certain other incremental costs and governmental authority taxes and costs. These monthly payment amounts, which are due on the 25th of the month prior to the month in which we provide services under the Total TUA, are equivalent to payments of $0.28 per MMBtu for capacity and $0.04 per MMBtu (subject to adjustment for inflation) for operating fees, respectively, of reserved monthly LNG receipt capacity. In addition, each month we are entitled to receive a “retainage” equal to 2% of the LNG delivered for Total’s account, which we will use primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility.

If any governmental authority (i) imposes any taxes on us (excluding taxes on revenue or income) with respect to the services provided under the TUA, or the LNG receiving terminal or (ii) enacts any safety or security related regulation which materially increases our costs in relation to the services provided or the LNG receiving terminal, Total will bear 40% of such taxes or increased regulatory costs. When LNG regasification capacity exceeds 3.0 Bcf/d, Total will thereafter bear a proportionate share of such taxes or increased regulatory costs, not to exceed 40%. After the Chevron and Total TUAs commence, we expect that Total’s proportionate share of such taxes and increased regulatory costs will be 25%. To the extent any ad valorem taxes are imposed and not abated, we will reimburse Total for up to one-half of such amount, not to exceed $3.9 million per year.

We are obligated to pay liquidated damages to Total in the event of certain types of docking and unloading delays.

Either party may assign its interests under the TUA to affiliates, and, as permitted by the TUA, we have pledged our interest under the TUA to the collateral trustee of the notes to secure our obligations under the notes. In addition, Total may make a partial assignment of its total reserved regasification capacity to nonaffiliates provided that (i) the assignee agrees to be bound by the TUA, (ii) the parent guarantee continues to apply to all assigned obligations and (iii) Total and the assignee designate a representative and jointly exercise all rights under the TUA.

An assignment under the TUA will extinguish Total’s or our obligations only if (i) the assignment constitutes all of such party’s rights and obligations under the TUA, (ii) the assignee agrees to be bound by the TUA and (iii) the assignee demonstrates creditworthiness at the time of the assignment that is the same as or better than the guarantor, in the case of Total, or us.

Total may terminate the TUA if we have declaredforce majeure with respect to a period that has extended, or is projected to extend, for 18 months, or for reasons not excused byforce majeure or Total’s actions, if we:

• fail to deliver at least 191,625,000 MMBtu of Total’s total natural gas nominations in a 12-month period;

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• fail entirely to receive at least 15 cargoes nominated by Total over a period of 90 consecutive days; or

• fail to unload 50 cargoes or more scheduled for delivery by Total for a 12-month period.

We may terminate the TUA if:

• the parent guarantee ceases to be in full force and effect;

• for a period exceeding 15 days, two of the parent guarantor’s credit ratings fall below investment grade; or

• the parent guarantor commences bankruptcy or liquidation proceedings, or has such proceedings commenced against it, and such proceedings are stayed within 60 days of service.

Either party may terminate the TUA with 30 days’ written notice if (i) a party has failed to pay when due an amount to the other party owed that causes its cumulative delinquency to exceed three times the monthly capacity reservation fee, (ii) the cumulative delinquency has not been paid within 60 days of such notice and (iii) the other party has subsequently given 30 days’ written notice to terminate the TUA.

In November 2004, Total exercised its option to proceed with the transaction by delivering to us an advance capacity reservation fee payment of $10 million and an irrevocable guarantee for an amount up to $2.5 billion by its parent entity, Total S.A., of Total’s payment obligations under the TUA, except for claims arising in tort or strict liability or claims for damages to property or personal injury. Because Total elected to proceed with the transaction and Bechtel accepted the final notice to proceed, or NTP, in April 2005, Total paid us an additional advance capacity reservation fee payment of $10 million.

We also entered into an omnibus agreement with Total in September 2004, under which the TUA remains subject to certain conditions. Under the omnibus agreement, if we enter into a new TUA with a third party, other than our affiliates, for capacity of 50 million cubic feet per day, or MMcf/d, or more, with a term of five years or more, prior to the commercial start date under the TUA, Total will have the option, exercisable within 30 days of the receipt of notice of such transaction, to adopt the pricing terms contained in such new TUA for the remainder of the term of the Total TUA. In addition, the omnibus agreement provides Total with an option to increase its reserved capacity in the event that either party provided notice of a plan to expand our LNG facility. During 2005, we provided such notice to Total, and Total’s option to increase its reserved capacity expired.

Chevron TUA

In November 2004, we entered into a TUA with Chevron to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at our LNG receiving terminal. We have no obligation to provide certain services such as (i) harbor, mooring and escort services for LNG vessels, including the provision of tugboats, (ii) the transportation of natural gas downstream from our LNG receiving terminal or the construction of any pipelines to provide such transportation or (iii) the marketing of natural gas.

In December 2005, Chevron exercised its option under its omnibus agreement to increase its regasification capacity by 300 MMcf/d for a total of 1.0 Bcf/d and paid us an additional $3 million advance capacity reservation fee. As a result of Chevron exercising its option, the TUA was amended to reflect the increased reservation of regasification capacity. Under the amended TUA, Chevron has reserved 403,945,500 MMBtu of annual LNG receipt capacity, which is equal to approximately 1.0 Bcf/d of regasification capacity, assuming an energy content of 1.085 MMBtu per Mcf and retainage of 2%.

Although Chevron could select a date as early as February 1, 2009, it is expected that payments of fees under the Chevron TUA will commence on July 1, 2009 (subject to achieving commercial operations completion by that date, and subject to delay caused by events offorce majeure). Chevron’s fees under the Chevron TUA are payable monthly in advance and will continue for a term of 20 years subject to two additional 10-year extensions. Under the Chevron TUA, Chevron is required to pay us a fixed monthly fee for this regasification capacity that

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consists of (i) a reservation fee of $9.4 million, (ii) an operating fee of $1.3 million and (iii) certain taxes and regulatory costs. The operating fee is adjusted annually for changes in the U.S. Consumer Price Index (All Urban Consumers). In addition, each month we are entitled to receive a “retainage” equal to 2% of the LNG delivered for Chevron’s account, which we will use primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. Chevron’s payments under the Chevron TUA are due on the 25th of the month prior to the month in which we provide services under the Chevron TUA. Chevron Corporation has guaranteed Chevron’s payment obligations under the TUA, up to a maximum of 80% of the fees payable under the TUA.

If any governmental authority (i) imposes any taxes on us (excluding taxes on revenue or income) with respect to the services provided under the TUA, or our LNG receiving terminal or (ii) enacts any safety or security related regulation which materially increases our costs in relation to the services provided at our LNG receiving terminal, Chevron will bear a proportionate share of such taxes or increased regulatory costs, not to exceed 28%. After the Chevron and Total TUAs commence, we expect that Chevron’s proportionate share of such taxes and increased regulatory costs will be 25%.

We are obligated to pay liquidated damages to Chevron in the event of certain types of docking and unloading delays.

Both parties may assign their interests under the TUA to affiliates, and, as permitted by the TUA, we have pledged our interest under the TUA to the collateral trustee of the notes to secure our obligations under the notes. In addition, Chevron may make a partial assignment of its total reserved regasification capacity to non-affiliates provided (i) the assignee agrees to be bound by the TUA, (ii) the parent guarantee continues to apply to all assigned obligations, (iii) Chevron remains liable for payments owed and (iv) the respective responsibilities of the parties under the TUA are not increased or decreased.

An assignment under the TUA will extinguish Chevron’s or our obligations only if (i) the assignment constitutes all of such party’s rights and obligations under the TUA, (ii) the assignee agrees to be bound by the TUA and (iii) the assignee demonstrates creditworthiness at the time of the assignment that is the same as or better than the guarantor, in the case of Chevron, or us.

Chevron may terminate the TUA if we have declaredforce majeure with respect to a period that has extended, or is projected to extend, for 18 months, or for reasons not excused byforce majeure or Chevron’s actions, if we:

• fail to deliver at least 191,625,000 MMBtu of Chevron’s total natural gas nominations in a 12-month period;

• fail entirely to receive 15 cargoes or more nominated by Chevron over a period of 90 days; or

• fail to unload, or notify Chevron that we would be unable to unload, 50 cargoes or more scheduled for delivery by Chevron for a 12-month period.

We may terminate the TUA if the parent guarantee ceases to be in full force and effect or if Chevron or its parent guarantor, Chevron Corporation, commences bankruptcy, insolvency or liquidation proceedings, or has such proceedings commenced against it, that are not stayed within 60 days.

Either party may terminate the TUA with 30 days’ written notice if (i) a party has failed to pay when due an amount owed to the other party that causes its cumulative delinquency to exceed three times the monthly capacity reservation fee, (ii) the cumulative delinquency has not been paid within 60 days after issuance of a delinquency notice and (iii) the other party has subsequently given 30 days written notice to terminate the TUA.

We simultaneously entered into an omnibus agreement with Chevron, under which Chevron agreed to make advance capacity reservation fee payments. Under the omnibus agreement, Chevron exercised an option in

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December 2005, at the same fee, to increase its reserved capacity to 1.0 Bcf/d. As a result, Chevron paid us a total of $20 million of advance capacity reservation fee payments under the omnibus agreement. In addition, the omnibus agreement provided Chevron with an option to increase its reserved capacity in the event that either party provided notice of a plan to expand our LNG facility. During 2005, we provided such notice to Chevron and its option expired.

Cheniere Marketing TUA

In November 2006, we entered into an amended and restated TUA with Cheniere Marketing, a wholly-owned subsidiary of Cheniere, to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at our LNG receiving terminal. We have no obligation to provide Cheniere Marketing with certain services such as (i) harbor, mooring and escort services for LNG vessels, including the provision of tugboats, (ii) the transportation of natural gas downstream from our LNG receiving terminal or the construction of any pipelines to provide such transportation or (iii) the marketing of natural gas.

Under the Cheniere Marketing TUA, Cheniere Marketing will pay fees to us based on 781,830,000 MMBtu of stipulated maximum annual LNG reception quantity, which is equivalent to approximately 2.0 Bcf/d of regasification capacity assuming an energy content of 1.05 MMBtu per Mcf and retainage of 2%.

Cheniere Marketing’s fees under the Cheniere Marketing TUA are payable monthly in advance commencing on the commercial start date (which will be the later of January 1, 2008 or the date when commercial operations completion is achieved), and will continue for a term of 20 years subject to four additional 10-year extension terms. Commercial operations completion will be achieved when our LNG receiving terminal is ready to be used for its intended purpose to provide the services called for under the Cheniere Marketing TUA, with Bechtel as contractor for the Phase 1 EPC agreement having achieved all minimum acceptance requirements under the Phase 1 EPC agreement sufficient to provide the services called for under the Cheniere Marketing TUA. Beginning on the commercial start date under the Cheniere Marketing TUA, Cheniere Marketing is required to pay us a fixed monthly fee for this regasification capacity that is comprised of: (i) a reservation fee of $0.28 per MMBtu times 1/12 of the reserved LNG receipt capacity; (ii) an operating fee of $0.04 per MMBtu times 1/12 of the stipulated maximum annual LNG reception quantity, which operating fee is adjusted annually for changes in the U.S. Consumer Price Index (All Urban Consumers); and (iii) certain other taxes and regulatory costs. Notwithstanding the foregoing, Cheniere Marketing is required to pay a flat fee of $5 million per month from the commercial start date under the Cheniere Marketing TUA through December 31, 2008. Cheniere Marketing’s payments under the Cheniere Marketing TUA are due on the 25th of the month prior to the month in which we provide services under the Cheniere Marketing TUA.

The stipulated maximum LNG reception quantity allocated to Cheniere Marketing is reduced to the extent that our LNG receiving terminal is unable to provide services up to such amount as a result of the timing of start dates under existing customer agreements (including the Total and Chevron TUAs) or delays in commencing commercial operation of the Phase 2 – Stage 1 expansion of our LNG receiving terminal; however, the fees to be paid by Cheniere Marketing under the Cheniere Marketing TUA will not be accordingly adjusted. In addition, each month, we are entitled to receive a “retainage” equal to 2% of the LNG delivered for Cheniere Marketing’s account, which we will use primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. All of Cheniere Marketing’s obligations during the initial 20-year term of the TUA are supported by an irrevocable guaranty in favor of us by Cheniere.

If any governmental authority (i) imposes any taxes on us (excluding taxes on revenue or income) with respect to the services provided under the Cheniere Marketing TUA, or our LNG receiving terminal or (ii) enacts any safety or security related regulation which materially increases our costs in relation to the services provided at our LNG receiving terminal, Cheniere Marketing will bear such taxes or increased regulatory costs at a rate proportional to its percentage of the right to use of our LNG receiving terminal’s total capacity.

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Both we and Cheniere Marketing may assign our respective interests under the Cheniere Marketing TUA to affiliates, as long as such assignment is not made prior to the first business day following the Cheniere Marketing TUA’s commercial start date. As permitted by the Cheniere Marketing TUA, we have pledged our interest under the TUA to the collateral trustee of the notes to secure our obligations under the notes. In addition, Cheniere Marketing may make a partial assignment of its total reserved regasification capacity (but not its rights to excess capacity described below) to non-affiliates provided that (i) the assignee agrees to be bound by the Cheniere Marketing TUA, (ii) Cheniere Marketing continues to be liable for all payments due under the Cheniere Marketing TUA, and (iii) Cheniere Marketing and the assignee designate a representative and jointly exercise all rights under the Cheniere Marketing TUA.

An assignment under the Cheniere Marketing TUA will terminate Cheniere Marketing’s obligations only if (i) the assignment constitutes all of Cheniere Marketing’s rights and obligations, (ii) the assignee agrees to assume all obligations of the assignor from inception of the Cheniere Marketing TUA, and (iii) the assignee demonstrates creditworthiness at the time of the assignment that is reasonably acceptable to us (and including credit standards that will be deemed acceptable).

Cheniere Marketing may terminate the Cheniere Marketing TUA if we have declaredforce majeure with respect to a period that has extended, or is projected to extend, for 18 months, or for reasons not excused byforce majeure or Cheniere Marketing’s actions, if we:

• fail to deliver at least 201,972,750 MMBtu of Cheniere Marketing’s total natural gas nominations in a 12-month period;

• fail entirely to receive at least 17 cargoes nominated by Cheniere Marketing over a period of 90 consecutive days; or

• fail to unload 53 cargoes or more scheduled for delivery by Cheniere Marketing for a 12-month period.

We may terminate the Cheniere Marketing TUA if Cheniere Marketing commences bankruptcy, reorganization or liquidation proceedings, or has such proceedings commenced against it, and such proceedings are not stayed within 60 days of service.

Either party may terminate the Cheniere Marketing TUA with 30 days’ written notice if (i) a party has failed to pay when due an amount owed to the other party that causes its cumulative delinquency to exceed three times the monthly capacity reservation fee, (ii) the cumulative delinquency has not been paid within 60 days of such notice and (iii) the other party has subsequently given 30 days’ written notice to terminate the Cheniere Marketing TUA.

The Cheniere Marketing TUA is designed to work in tandem with the Total TUA and the Chevron TUA and states that no provision of the Cheniere Marketing TUA shall be effective if and to the extent that it expressly conflicts with a provision of the Total TUA or the Chevron TUA. Any excess capacity at our LNG receiving terminal that we are not contractually obligated to make available to any other customer, and any capacity that any other customer elects not to use, may be used exclusively by Cheniere Marketing without any additional charge or fee except for 2% retainage and port charges in respect of vessels entering or leaving our LNG receiving terminal. This excess capacity may be available from time to time, including at completion of Phase 1 and the outset of commercial operation of our LNG receiving terminal, which is the date on which our LNG receiving terminal is projected to have capacity of 2.6 Bcf/d.

The effective date at which Cheniere Marketing is to purchase and pay for services from our LNG receiving terminal is the later of January 1, 2008 or the date of commercial operations completion, which is currently expected to occur during the second quarter of 2008.

The Cheniere Marketing TUA provides that, at Cheniere Marketing’s request, we must construct a sixth LNG storage tank with a working capacity of approximately 160,000 cubic meters of LNG for the benefit of

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Cheniere Marketing 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 our receipt of all FERC and other required governmental permits and approvals and obtaining financing that we consider reasonably acceptable in form and content.

We have entered into a letter agreement with Cheniere Marketing in which we have agreed to enter into a contingent TUA with J & S Cheniere S.A., or J & S Cheniere, a Swiss entity in which Cheniere holds a 49% minority interest, if and when applicable, and Cheniere Marketing has agreed to relinquish 78,475,000 MMBtus of stipulated maximum annual LNG reception quantity (and proportionately reduce its fixed monthly fee) under the Cheniere Marketing TUA if required to allow us to satisfy our obligations under the J & S Cheniere contingent TUA described below. This letter agreement cancels and supersedes the similar November 2006 letter agreement between us and Cheniere Marketing that related to a potential TUA with J & S Cheniere under its now-terminated December 2003 option agreement.

In replacement of such terminated option, Cheniere Marketing and J & S Cheniere agreed to continue negotiating LNG sale and purchase agreements that would provide for the sale by J & S Cheniere of approximately 78,475,000 MMBtus of stipulated maximum annual LNG reception quantity to Cheniere Marketing for delivery at our LNG receiving terminal. As contemplated in a form of sale and purchase agreement attached to the J & S Cheniere shareholders agreement, J & S Cheniere would be able to “put” to Cheniere Marketing approximately 78,475,000 MMBtus of stipulated maximum annual LNG reception quantity with a minimum obligation to deliver one cargo per year (approximately 3.0 Bcf of LNG), or pay an agreed upon amount if such cargo is not delivered, to our LNG receiving terminal, at a price based on an agreed percentage of the price of natural gas at the NYMEX Henry Hub. The form of sale and purchase agreement also contemplates that, in the event the sale and purchase agreement is terminated by J & S Cheniere because Cheniere Marketing fails to perform its purchase or payment obligations, or becomes bankrupt, or because a change of control of Cheniere has occurred, we would enter into a TUA with J & S Cheniere covering approximately 78,475,000 MMBtus of stipulated maximum annual LNG reception quantity for our LNG receiving terminal, so long as our LNG receiving terminal has commenced commercial operation.

FERC and Other Governmental Regulation

Our LNG operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and other laws. Among other matters, these laws require that we engage in consultations with certain federal and state agencies and that we obtain certain permits and other authorizations before commencement of construction and operation of our LNG receiving terminal. This regulatory burden increases the cost of constructing and operating our LNG receiving terminal, and failure to comply with such laws could result in substantial penalties.

Federal Energy Regulatory Commission

In order to site and construct our LNG receiving terminal, we were required to receive and are required to maintain authorization from the FERC under Section 3 of the NGA. The FERC permitting process includes:

• initial public notice and public meetings;

• data gathering and analysis at the FERC’s request;

• issuance of a Draft Environmental Impact Statement by the FERC;

• additional public meetings, as warranted;

• issuance of a Final Environmental Impact Statement by the FERC;

• the FERC order authorizing construction; and

• issuance by the FERC of the construction notice to proceed.

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We received the FERC authorization to construct both Phase 1 and Phase 2 – Stage 1, although those authorizations are subject to specified conditions that must be satisfied throughout the construction, commissioning and operation of the terminal. Those conditions require us to:

• appoint third-party environmental inspectors to monitor compliance with the FERC’s conditions;

• submit any material changes to the design or construction of the facility for FERC approval;

• submit an implementation plan for compliance with the FERC-ordered mitigation measures;

• submit monthly and weekly construction reports detailing construction progress and ongoing compliance efforts;

• comply with U.S. Fish and Wildlife Service guidelines regarding lighting;

• file a Coastal Zone Management Plan consistency determination;

• limit construction activities to comply with noise limits and regulations and file a noise survey; and

• file plans regarding the installation, implementation and operation of various safety measures and comply with those plans.

In addition, throughout the life of our LNG receiving terminal, we will be subject to regular reporting requirements to the FERC regarding the operation and maintenance of the facility.

Other Federal Governmental Permits, Approvals and Consultations

In addition to FERC authorization under Section 3 of the NGA, our construction and operation of our LNG receiving terminal is also subject to additional federal permits, approvals and consultations required by certain other federal agencies, including: Advisory Counsel on Historic Preservation, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, U.S. Environmental Protection Agency and U.S. Department of Homeland Security.

Our LNG receiving terminal will also be subject to U.S. Department of Transportation siting requirements and regulations of the U.S. Coast Guard relating to facility security. Moreover, our LNG receiving terminal will be subject to local and state laws, rules and regulations.

Energy Policy Act of 2005

In 2005, the Energy Policy Act of 2005, or EPAct, was signed into law. The EPAct contains numerous provisions relevant to the natural gas industry and to interstate pipelines. The EPAct includes several provisions which amend the NGA. The primary provisions of interest to our operations focus on two areas: infrastructure development, and market manipulation and enforcement. Regarding infrastructure development, the EPAct states that the FERC has exclusive authority to approve or deny an application for the siting, construction, expansion or operation of an LNG receiving terminal. Regarding market manipulation and enforcement, the EPAct amends the NGA to prohibit market manipulation. The EPAct also amends the NGA and the Natural Gas Policy Act of 1978, or NGPA, to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of the FERC up to $1 million per day per violation. In addition, the FERC issued a final rule effective January 26, 2006 regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. This final rule works together with the FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace.

Environmental Regulation

Our LNG operations are subject to various federal, state and local laws and regulations relating to the protection of the environment. In some cases, these laws and regulations require us to obtain governmental

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permits and authorizations before we may conduct certain activities. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial liabilities for non-compliance or 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. As with the industry generally, our operations will entail risks in these areas, and compliance with these laws and regulations increases our overall cost of business. While these laws and regulations affect our capital expenditures and earnings, we believe that these laws and regulations do not affect our competitive position in the industry because our competitors are similarly affected. Environmental laws and regulations have historically been subject to frequent revision and reinterpretation. Consequently, we are unable to predict the future costs or other future impacts of environmental regulations on our future operations.

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault, on certain classes of persons who are considered to be responsible for the spill or release of a hazardous substance into the environment. Potentially liable persons include the owner or operator of the site where the release occurred and persons who disposed or arranged for the disposal of hazardous substances at the site. Under CERCLA, responsible persons may be subject to joint and several liability for:

• the costs of cleaning up the hazardous substances that have been released into the environment;

• damages to natural resources; and

• the costs of certain health studies.

In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances. Although CERCLA currently excludes petroleum, natural gas, natural gas liquids and LNG from its definition of “hazardous substances,” this exemption may be limited or modified by the U.S. Congress in the future.

Clean Air Act (CAA)

Our operations are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing other air emission-related issues. We do not believe, however, that our operations will be materially adversely affected by any such requirements.

The U.S. Supreme Court has ruled that the Environmental Protection Agency has authority under existing legislation to regulate carbon dioxide and other heat-trapping gases in mobile source emissions. In addition, Congress is currently considering proposed legislation directed at reducing “greenhouse gas emissions.” It is not possible at this time to predict how future regulations or legislation may address greenhouse gas emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial position, results of operations and cash flows.

Certain persons have expressed concerns that air emissions from our LNG receiving terminal, which are allowed under our existing permits, could adversely impact regional air quality in southeastern Texas so as to trigger future federal sanctions for that area under the CAA. While we have no reason to believe that any formal challenge will be made regarding our existing permits under the CAA, such challenges may be pursued and, if pursued, may result in costs or conditions that could have a material adverse effect on our business and operations.

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Clean Water Act (CWA)

Our operations are also subject to the federal CWA and analogous state and local laws. Pursuant to certain requirements of the CWA, the EPA has adopted regulations concerning discharges of wastewater and storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit.

Resource Conservation and Recovery Act (RCRA)

The federal RCRA and comparable state statutes govern the disposal of “hazardous wastes.” In the event any hazardous wastes are generated in connection with our LNG operations, we may be subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

Endangered Species Act

Our operations and planned construction activities may also be restricted by requirements under the Endangered Species Act, which seeks to ensure that human activities do not jeopardize endangered or threatened animal, fish and plant species nor destroy or modify their critical habitats.

Competition

We currently do not experience competition because the entire approximately 4.0 Bcf/d of regasification capacity that will be available at our LNG receiving terminal upon completion of Phase 2 – Stage 1 has been fully reserved under three 20-year TUAs under which our customers are generally required to pay monthly capacity fees on a “take-or-pay” basis.

According to the FERC, as of December 18, 2006, there were six existing LNG receiving terminals in North America, including one offshore facility for receiving LNG regasified aboard specialized LNG vessels, as well as 44 new LNG receiving terminals or expansions approved or proposed to be constructed in the U.S., of which six are under construction. If and when we have to replace any TUAs, we will compete with these existing and proposed North American LNG receiving terminals and their customers. Cheniere is currently developing two of these proposed LNG receiving terminals. With the exception of Cameron LNG, we believe that all of the capacity at the five existing onshore U.S. terminals and all of the capacity at the six terminals or expansions under construction is committed to customers under long-term arrangements. As of December 31, 2005, there were 51 LNG receiving terminals in 15 countries, and if and when we have to replace any TUAs, we will compete with these and other proposed LNG receiving terminals worldwide to be the most economical delivery point for LNG production for both long-term contracted and spot volumes.

Insurance

We maintain a comprehensive insurance program to insure against potential losses to our LNG receiving terminal from physical loss or damage, hurricanes and terrorism, as well as third-party liabilities, during construction and subsequent operation. We have engaged Aon Risk Services, Inc., or Aon, as our independent insurance advisor. Aon has provided independent validation regarding the appropriateness of our insurance policies compared to other selected benchmark projects. We may not be able to maintain adequate insurance in the future at rates that are considered reasonable. See “Risk Factors—Risks Relating to Development and Operation of our Business—We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities for us.”

Insurance During Construction Period

During construction of Phase 1, under terms of the EPC contract, Bechtel is responsible for obtaining for us substantially all of the required insurance covering loss or damage to assets, loss of income due to a delay in our

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LNG receiving terminal’s completion, and third-party liabilities. Terrorism insurance and our primary auto liability insurance are excluded from Bechtel’s contractual obligations and have been procured by us directly. Upon substantial completion of Phase 1, we will assume responsibility of maintaining the insurance program. Bechtel has obtained expansions of Phase 1 policies to insure Phase 2 – Stage 1 exposures.

Windstorm and Flood Insurance

For Phase 1 and Phase 2 – Stage 1, we have $400 million in total windstorm and flood insurance, $100 million of which is shared with Phase 2 – Stage 1. This aggregate $400 million limit applies to physical damage losses. Aon has deemed the current insurance package as appropriate for this type of facility and takes into account damage or loss of the paint, loss of income exposure and potential liabilities to third parties.

Physical Damage and Delayed Start up Insurance

For Phase 1 and Phase 2 – Stage 1, we have total insurance coverage against property damage of approximately $1.1 billion, subject to stated sublimits. We have $259 million in both builder’s risk and marine cargo delayed start up, or DSU, insurance in addition to the property damage insurance. This DSU limit also applies to windstorm and flood losses. For Phase 2 – Stage 1, the builder’s risk property damage limit was increased by $448 million to cover additional insurable Phase 2 – Stage 1 assets. We do not intend to acquire builder’s risk DSU or marine cargo DSU insurance for delays in the completion of Phase 2 – Stage 1. Delays in completion of Phase 1 are insured under the builder’s risk DSU and marine cargo DSU policies.

Third-Party Liability

We have $100 million of third-party liability insurance shared between Phase 1 and Phase 2 – Stage 1. Due to changes in the risk of loss and required amount of insurance for major Phase 2 – Stage 1 construction contractors, we placed an additional $100 million of third-party liability insurance during construction dedicated to only Phase 2 – Stage 1.

Pollution Legal Liability

We have $25 million of pollution legal liability insurance covering third-party liabilities, remediation legal liability, and legal defense expense. This limit is shared by both Phase 1 and Phase 2 – Stage 1.

Terrorism

Aon reported in October 2006 that there was limited exposure to physical damage and subsequent loss of income arising out of a terrorist act against Phase 1. Aon believes that this risk is unlikely to change significantly as a result of Phase 2 – Stage 1. Until the first LNG tanker reaches our LNG receiving terminal, we have $25 million of terrorism insurance. Prior to the arrival of the first LNG tanker, we intend to complete a terrorism maximum foreseeable loss study that incorporates Phase 1 and Phase 2 – Stage 1. We plan to assess the scope of our terrorism insurance policy upon completion of this study.

Insurance During Operational Period

Upon commencement of operations, we will have responsibility for all insurance coverage, including those previously obtained for us by Bechtel. We intend to place insurance coverages that are in such form and amounts as are customary for project facilities of similar type and scale to this facility.

Employees

We have no employees. We will rely on a subsidiary of Cheniere to provide all necessary services required to construct, operate and maintain our LNG receiving terminal. In addition, we have appointed our general

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partner to manage all aspects of the construction and operation of our LNG receiving terminal not managed by such subsidiary of Cheniere. Because our general partner has no employees, it will rely on subsidiaries of Cheniere to provide the personnel necessary to allow our general partner to meet its management obligations to us. See “Certain Relationships and Related Transactions” for a discussion of these arrangements.

Legal Proceedings

We are not a party to any legal proceeding but may in the future be a party to various administrative, regulatory or other legal proceedings that may arise in the ordinary course of our business. Like Cheniere and its other affiliates, we will regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of such matters. In the opinion of management of our general partner, as of December 31, 2006, there were no threatened or pending legal matters that would have a material impact on results of operations, financial position or cash flows.

As previously disclosed by Cheniere, Cheniere received a letter from the SEC, dated December 17, 2004, advising it of a nonpublic, informal inquiry being conducted by the SEC. On August 9, 2005, the SEC informed Cheniere that it had issued a formal order to commence a nonpublic factual investigation of actions and communications by Cheniere, Cheniere’s current or former directors, officers and employees and other persons in connection with our agreements and negotiations with Chevron USA, Cheniere’s December 2004 public offering of common stock, and trading in its securities. The scope, focus and subject matter of the SEC investigation may change from time to time, and Cheniere may be unaware of matters under consideration by the SEC. Cheniere has publicly disclosed that it has cooperated fully with the SEC informal inquiry and intends to continue to cooperate fully with the SEC in its investigation. Cheniere has advised us that it has not received any communication from the SEC with regard to this matter since September 2005.

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DESCRIPTION OF PRINCIPAL PROJECT DOCUMENTS

The following are summaries of material terms of certain agreements related to the construction of our LNG receiving terminal. These summaries should not be considered to be a full statement of the terms and provisions of such agreements. Accordingly, the following summaries are qualified in their entirety by reference to each agreement. Copies of the agreements described below are filed as exhibits to the registration statement of which this prospectus is a part. Unless otherwise stated, any reference in this prospectus to any agreement means such agreement and all schedules, exhibits and attachments thereto as amended, supplemented or otherwise modified and in effect as of the date hereof.

Phase 1 EPC Agreement

Scope of Work

In December 2004, we entered into a lump-sum turnkey EPC agreement with Bechtel for the construction of Phase 1 of our LNG receiving terminal. Under the EPC agreement, Bechtel agreed to provide us with services for the engineering, procurement and construction of our LNG receiving terminal. Except for certain specified owner and third-party work outlined 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 our LNG receiving terminal in accordance with the requirements of the EPC agreement, including achieving specified minimum acceptance criteria and performance guarantees. Bechtel is obligated to perform its work in accordance with good engineering and construction practices and applicable laws, codes and standards.

We issued a limited notice to proceed, or LNTP, in December 2004 and an NTP in early April 2005, which required Bechtel to commence all other aspects of the work under the EPC agreement. Bechtel must achieve substantial completion in accordance with the requirements of the EPC agreement on or before December 20, 2008. Final completion must be attained no later than 90 days after achieving substantial completion.

Payment for Work

We agreed to pay to Bechtel a contract price of $646.9 million plus certain reimbursable costs for the work under the EPC agreement. This contract price is subject to adjustment for contingencies, change orders and other items. As of April 30, 2007, change orders for $132.3 million had been approved, increasing the total contract price to $779.2 million. Payments under the EPC agreement will be made in accordance with the payment schedule set forth in the EPC agreement. The contract price and payment schedule, including milestones, may be amended only by change order. Bechtel will be liable to us for certain delays in achieving substantial completion, minimum acceptance criteria and performance guarantees. Bechtel will be entitled to a scheduled bonus of $12 million if on or before April 3, 2008, Bechtel completes construction sufficient to achieve, among other requirements specified in the EPC agreement, a sustained revaporized natural gas sendout at a significant rate for a preagreed period of time (currently provided to be a rate of at least 2.0 Bcf/d for a minimum sustained test period of 24 hours). The amount of such scheduled bonus will decrease by a specified amount for each day after April 3, 2008, that Bechtel fails to meet this test, up to a total of 40 days. The specified amount per day is $125,000 for the first 15 days, $300,000 for the next 10 days and $475,000 for the next 15 days. Bechtel will be entitled to receive an additional bonus of $67,000 per day (up to a maximum of $6 million) for each day that commercial operation is achieved prior to April 1, 2008.

Change Orders

Until substantial completion under the terms of the EPC agreement, we have certain rights to request change orders, and Bechtel has the right to request change orders up to and after substantial completion in the event of specified occurrences, including, among other things:

• aforce majeure event;

• a suspension of work ordered by us;

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• certain acts and omissions by us (including failure to fulfill obligations), but, in each case, only where such act or omission adversely affects Bechtel’s costs of the performance of work, its ability to perform the work in accordance with the project schedule or its ability to perform any material obligation under the EPC agreement; and

• certain changes in law, but only where such delay adversely affects Bechtel’s costs of the performance of the work, its ability to perform the work in accordance with the project schedule or its ability to perform any material obligation under the EPC agreement.

Liquidated Damages

Bechtel is required to pay “delay” liquidated damages for each day of delay that Bechtel fails to complete the work necessary to commence the cool down phase at our LNG receiving terminal beyond a date estimated by Bechtel for completion of such work. The maximum aggregate amount of liquidated damages for such delay is one percent of the contract price. In addition, Bechtel is required to pay liquidated damages for each day of delay beyond December 20, 2008 that Bechtel fails to achieve substantial completion. The maximum aggregate amount of all delay liquidated damages is 10% of the contract price.

In addition, if our LNG receiving terminal fails to achieve one or more performance guarantees relating to sendout rate and ship unloading time by December 20, 2008, but meets specified minimum acceptance criteria and all other requirements for substantial completion, then Bechtel is required to pay “performance” liquidated damages for such failure. The maximum aggregate amounts of performance liquidated damages related to sendout rate and ship unloading time are 10% of the contract price and 2% of the contract price, respectively. The maximum aggregate amount of all performance liquidated damages is 10% of the contract price.

Subject to certain exceptions, Bechtel’s maximum aggregate liability under the EPC agreement (including its liability for liquidated damages) is 30% of the contract price.

Warranty

Bechtel warrants in the EPC agreement that:

• the equipment required for our LNG receiving terminal will be new and of good quality;

• the work and the equipment will meet the requirements of the EPC agreement, including good engineering and construction practices and applicable laws, codes and standards; and

• the work and the equipment will be free from encumbrances to title.

Until 18 months after our provisional acceptance of our LNG receiving terminal, Bechtel will be liable for promptly correcting any work that is found to be defective.

Force Majeure

Under the EPC agreement, if Bechtel experiences aforce majeure event, it could be entitled to an extension of the date by which substantial completion is to be accomplished and an extension of the date by which it could earn the $12 million bonus. If anyforce majeure delay lasts at least 30 days, Bechtel would be entitled to an adjustment of the contract price under the EPC agreement to compensate it for its standby expenses, up to a limit of $3.8 million in the aggregate. Aforce majeure event generally occurs if any act or event occurs that:

• prevents or delays the affected party’s performance of its obligations in accordance with the terms of the EPC agreement;

• is beyond the reasonable control of the affected party, not due to its fault or negligence; and

• could not have been prevented or avoided by the affected party through the exercise of due diligence.

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Bechtel has claimed events offorce majeure arising out of three hurricanes that made landfall along the U.S. Gulf Coast in 2005. We have entered into change orders with Bechtel concerning additional activities and expenditures in order, among other things, to attract sufficient skilled labor to mitigate potential schedule delays and provide a reasonable opportunity for Bechtel to attain the initial target bonus date of April 3, 2008 (the date originally anticipated for completion of construction sufficient to achieve a sendout rate of at least 2.0 Bcf/d for a minimum sustained test period of 24 hours and that, if attained, would entitle Bechtel to a scheduled $12 million bonus). In a change order dated May 16, 2006, we agreed to defer the date by which substantial completion of the entire project is required to be accomplished under the EPC agreement from September 3 to December 20, 2008, which is the new substantial completion date. In the absence of substantial completion by such date, Bechtel would be obligated to pay us certain liquidated damages as provided under the terms of the contract.

Termination and Suspension

In the event of an uncured default by Bechtel, we may terminate the EPC agreement and take any of the following actions:

• take possession of the facility, equipment, construction equipment, work product and books and records;

• take assignment of certain subcontracts; and

• complete the work.

Following such a termination, if the cost to reach final completion exceeded the unpaid balance of the contract price, Bechtel would be liable for the difference, subject to Bechtel’s limitation of liabilities described above. If the cost to reach final completion were less than the unpaid balance of the contract price, the difference would be payable to Bechtel.

We also have the right to terminate the EPC agreement for convenience. In the event of any such termination for convenience, Bechtel would be paid:

• the portion of the contract price for the work performed prior to termination, less that portion of the contract price paid previously;

• actual reasonable cancellation charges owed by Bechtel to subcontractors (if we do not take assignment of such subcontracts);

• actual costs associated with demobilization charges; and

• lost profits, except in certain cases, equal to 10% of the contract price less a portion of the advance payment related to the NTP.

We may, upon a 30-day written notice to Bechtel, suspend the work under the EPC agreement. In the event of such suspension for a period exceeding 90 consecutive days or 120 aggregate days, other than any suspension due to an event offorce majeure or the fault or negligence of Bechtel or its subcontractors, Bechtel would be permitted to terminate the EPC agreement subject to giving 14 days’ notice. In the event of such a termination, Bechtel would be entitled to the compensation described above in relation to termination for convenience. If we suspend work under the EPC agreement, Bechtel could be entitled to a change order to recover the reasonable costs of the suspension, including demobilization and remobilization costs. Bechtel may also suspend or terminate the EPC agreement upon the occurrence of certain other events, includingforce majeure and our uncured defaults, such as:

• failure to pay any undisputed amounts;

• failure to comply materially with material obligations under the EPC agreement; and

• insolvency.

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Phase 2 – Stage 1 EPCM Agreement

Scope of Work

In July 2006, we entered into an Agreement for Engineering, Procurement, Construction and Management of Construction Services of the Phase 2 Receiving, Storage and Regasification Terminal Expansion, or the EPCM agreement, with Bechtel. Under the EPCM agreement, Bechtel will provide design and engineering services for Phase 2 – Stage 1 of our LNG receiving terminal expansion project, except for such portions to be designed by other contractors and suppliers of equipment, materials and services that we contract with directly, who we refer to as the Sabine contractors, and those obligations that must be performed directly by Sabine Pass LNG; construction management services to manage the construction of the facility; and performance of a portion of the construction. The EPCM agreement does not contain any guaranteed completion dates, but Bechtel will provide a schedule for our approval.

Payment for Work

The EPCM agreement provides for compensating Bechtel 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 our sole discretion upon completion of Phase 2 – Stage 1. Payments under the EPCM agreement will be based on monthly estimates, with a reconciliation in the next month, and the fixed fee will be paid in accordance with a payment schedule set forth in the EPCM agreement. In addition to disputed amounts, we may, upon giving prior written notice and subject to specified cure periods, withhold payment or a portion thereof, in an amount and to such extent as may be reasonably necessary to protect us from loss due to:

• defective services;

• liens or other encumbrances on all or a portion of the Phase 2 site or the Phase 2 facility filed by Bechtel or any subcontractor or any person acting through or under any of them;

• any material breach by Bechtel of any provision of the EPCM agreement;

• the assessment of any fines or penalties against us as a result of Bechtel’s failure to comply with applicable law or applicable codes and standards;

• amounts we paid to Bechtel in a preceding month incorrectly; or

• any other costs and liabilities that we have incurred for which Bechtel is responsible under the EPCM agreement.

Bechtel has the right to submit a change order to us to increase the fixed fee:

• in the event that we adjust the scope of Phase 2 – Stage 1 at a cost individually or in the aggregate of $5,000,000 or more, excluding any increased costs caused by escalation in the cost of labor or materials, estimating errors or higher than expected costs for labor, materials or equipment;

• for significant delays to Phase 2 – Stage 1 resulting from aforce majeure event (as described below) causing a delay in excess of 90 consecutive days;

• if we suspend all or a significant portion of Phase 2 – Stage 1 for more than 60 consecutive days; or

• if we direct Bechtel or our Sabine contractors to significantly delay the progress of Phase 2 – Stage 1.

In such circumstances, Bechtel will be entitled to an adjustment in the fixed fee of $200,000 for each $5,000,000 in the cost of Phase 2 – Stage 1.

Warranty

Bechtel warrants that the materials, equipment and supplies provided by Bechtel and its subcontractors (but not our contractors) will be new and of good quality; the services will be provided in accordance with all

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requirements of the EPCM agreement; and all equipment, materials and supplies furnished by Bechtel and its subcontractors will be free from encumbrances to title. There are three distinct defect correction periods, and during any such period and for 18 months thereafter, Bechtel is responsible for promptly correcting any defective service and performing any other services necessary to correct the defect to the Phase 2 – Stage 1 facility. Bechtel will be reimbursed on a recoverable cost basis for performing corrective services, including the cost of field labor, field supervision, materials and equipment, but Bechtel will not be entitled to payment for any costs associated with design, engineering, construction management, or for the costs of field personnel above a rank of general foreman. In addition, Bechtel will not be entitled to any increase in the fixed fee in connection with the performance of corrective services.

Limitation of Liability

Bechtel’s liability in contract, warranty, tort, strict liability, products liability, professional liability, indemnity, contribution or any other cause is limited to the amount of 50% of the fixed fee (as adjusted pursuant to a change order), except that this limitation does not apply to: (i) Bechtel’s indemnification obligations; (ii) proceeds of insurance required to be obtained by Bechtel and its subcontractors; or (iii) Bechtel’s obligation to deliver unencumbered title to us in accordance with the EPCM agreement for materials, equipment and supplies furnished by Bechtel or its subcontractors.

Force Majeure

Because the EPCM agreement is cost-reimbursable, no change order is required for costs incurred by Bechtel related to aforce majeure event. Any costs incurred by Bechtel in exercising reasonable efforts to prevent, avoid, overcome or mitigate the effects offorce majeure on Phase 2 – Stage 1 will be recoverable under the cost reimbursable structure. Aforce majeure under the EPCM agreement is any act or event that:

• prevents or delays the affected party’s performance of its obligations in accordance with the terms of the EPCM agreement;

• is beyond the reasonable control of the affected party, not due to its fault or negligence; and

• could not have been prevented or avoided by the affected party through the exercise of due diligence.

Termination and Suspension

In the event of an uncured default by Bechtel, we may terminate the EPCM agreement and take any of the following actions:

• take possession of the facility, materials, equipment, construction equipment, work product, books and records and other items owned or rented by Bechtel;

• take assignment of any or all subcontracts; and

• complete the work.

Following such a termination, we have no further obligation to pay Bechtel, and Bechtel must refund any advance payments made for services not yet performed, and Bechtel will be liable for reasonable costs incurred by us due to the default.

We also have the right to terminate the EPCM agreement for convenience upon 30 days’ prior written notice to Bechtel. In the event of any such termination for convenience, Bechtel would be paid:

• all recoverable costs for services performed through the date of termination, less that portion of the recoverable costs previously paid;

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• all recoverable costs reasonably incurred by Bechtel on account of such termination, including cancellation charges owed by Bechtel to its subcontractors if we do not take assignment of such subcontracts, and costs associated with demobilization of personnel and construction equipment; and

• the fixed fee for services performed through the date of termination, less amounts previously paid.

Bechtel’s ability to terminate the EPCM agreement is limited to the following events:

• our failure to pay an undisputed amount, if such failure is not cured within 45 days after notice from Bechtel;

• our failure to materially comply with any of our material obligations under the EPCM agreement (but only to the extent such material failure and the impact thereof is not subject to adjustment by change order), and we fail to cure such failure within 45 days (or a reasonable time beyond 45 days, not to exceed 90 days) after notice from Bechtel; or

• we experience an insolvency event.

In the event of any such termination event, Bechtel is entitled to the same compensation set forth above as if we had terminated for convenience.

If anyforce majeure event or the effects thereof causes suspension of a substantial portion of the work at the Phase 2 site for a period exceeding 90 consecutive days or 180 days in the aggregate during any continuous 24-month period, then either party has the right to terminate the EPCM agreement by providing 14 days’ written notice to the other party. In the event of such termination, Bechtel is entitled to the same compensation set forth above as if we had terminated the EPCM agreement for convenience.

We may, upon 10 days’ written notice to Bechtel, suspend the work under the EPCM agreement. In the event such suspension period exceeds 90 consecutive days or 180 aggregate days, Bechtel is permitted to terminate the EPCM agreement subject to giving 14 days’ written notice to us. Bechtel is also permitted to suspend performance of its services after 14 days’ prior written notice if we fail to pay any undisputed amount due and owing to Bechtel and such failure continues for more than 30 days after the due date for such payment.

Phase 2 – Stage 1 EPC LNG Tank Contract

Scope of Work

In July 2006, we entered into an Engineer, Procure and Construct (EPC) LNG Tank Contract, or the tank contract, with Zachry and Diamond (each of whom is jointly and severally liable for obligations under the tank contract), who are collectively referred to as the tank contractor, for the Phase 2 – Stage 1 expansion of our LNG receiving terminal. Under the tank contract, the tank contractor 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 the materials for and construct two Phase 2 – Stage 1 tanks, except as otherwise specified in the tank contract.

Scheduling

The target milestone completion date of the first Phase 2 – Stage 1 tank is scheduled in the first quarter of 2009, and the target milestone completion date of the second Phase 2 – Stage 1 tank is scheduled in the second quarter of 2009.

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Payments

The tank contract provides that the tank contractor will receive a lump-sum, fixed price payment of approximately $140.9 million. The contract price is subject to adjustment based on fluctuations in the cost of labor and certain materials for the Phase 2 – Stage 1 tanks, including the nickel steel used in the Phase 2 – Stage 1 tanks.

Payments under the tank contract will be made in accordance with a specified milestone payment schedule. As retainage, we withhold 5% of each milestone payment for the work performed up to provisional acceptance. One-half of the retainage will be released upon provisional acceptance of the first Phase 2 – Stage 1 tank, and the remaining retainage will be released upon provisional acceptance of the second Phase 2 – Stage 1 tank.

In addition to disputed invoice amounts, we may, upon giving prior written notice and allowing the tank contractor an opportunity to cure, withhold payment on an invoice or a portion thereof, or collect on the letter of credit, if:

• the tank contractor is in default of any tank contract condition, including, but not limited to, the schedule, quality assurance and health and safety requirements;

• the tank contractor has not submitted the tank contract schedule, including any revisions or updates, as required by the tank contract;

• the tank contractor has failed to submit proper insurance certificates, or not provided proper coverage or proof thereof;

• the tank contractor has failed to submit securities approved by us;

• the tank contractor fails to submit interim lien waivers from the tank contractor and major subcontractors; or

• adjustments are due from previous overpayment or audit results.

Letter of Credit

The tank contractor has furnished us with an irrevocable standby letter of credit in the amount of 5% of the contract price, issued and confirmed by a bank acceptable to us. The letter of credit will expire upon final acceptance of the two Phase 2 – Stage 1 tanks and our notice to the issuing bank to release the letter of credit. If at any time the contract price is increased by change order by at least 1% of the contract price, in the aggregate, the tank contractor will increase the amount of the letter of credit to 5% of the adjusted contract price. In addition, Mitsubishi Heavy Industries Ltd. has executed a guarantee agreement with respect to the obligations of Diamond under the tank contract.

Change Orders

We have the right to submit any change order, subject to certain caps on unilateral change orders (including an individual cap of 5% and an aggregate cap of 10% of the contract price).

The tank contractor has the right to submit a change order in the event of specified circumstances, including the following:

• a change in law;

• acts or omissions by us that constitute a change in the work under the tank contract;

• force majeure;

• acceleration of the work directed by us;

• if the finished work conforms with the requirements of the tank contract, but we require disassembling or dismantling of a tank for the purpose of inspection;

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• in the event of a delay or suspension of work ordered by or on behalf of us;

• in the event subsurface soil conditions are materially different from the information provided by us; and

• discovery of pre-existing hazardous material at the site.

In many instances, before such a change order can be submitted by the tank contractor, such occurrences must adversely affect the tank contractor’s (i) cost of performing the work; (ii) ability to perform the work in accordance with the project schedule; or (iii) ability to perform any material obligation under the tank contract.

Liquidated Damages

The tank contractor is required to pay liquidated damages for each day of delay that the tank contractor fails to achieve mechanical completion for each Phase 2 – Stage 1 tank by the respective mechanical completion milestone date. The amount of the liquidated damages for each tank is $50,000 for each of the first 75 days of delay and $100,000 for each day thereafter, subject to a maximum of 10% of the contract price.

Limitation of Liability

The tank contractor is obligated to perform all of the work required to achieve ready for cool down for both of the Phase 2 – Stage 1 tanks. Once both of the Phase 2 – Stage 1 tanks are ready for cool down, liability under the tank contract or under any cause of action related to the subject matter of the tank contract, whether in contract, warranty, tort, strict liability, products liability, professional liability, indemnity, contribution or any other cause of action, is limited to an aggregate of 30% of the contract price, except that this limitation does not apply to: (i) losses caused by criminal acts, fraud or gross negligence of the tank contractor’s key personnel or their superiors; (ii) the tank contractor’s indemnification obligations under the tank contract; or (iii) proceeds of insurance required to be obtained by the tank contractor and its subcontractors and sub-subcontractors.

Warranty

The tank contractor warrants that the work (including all materials and equipment) will be new (unless otherwise agreed) and of good quality, in accordance with all requirements of the tank contract (including good engineering and construction practices, applicable law and applicable codes and standards), and free from encumbrances to title. Until the end of the defect correction period (ending 18 months after provisional acceptance of each Phase 2 – Stage 1 tank or 24 months after each Phase 2 – Stage 1 tank is ready for cool down, whichever occurs first, and subject to extension for corrected work, and subject to extension for corrected work, and up to 30 months if the Phase 2 – Stage 1 tank ceases operating solely because of defects in the work or corrections therefor, to the extent of the interruption in operations), the tank contractor is liable to promptly correct any work that is found to be defective.

Force Majeure

Aforce majeure event entitles the tank contractor to an extension to the project schedule if the delay caused by theforce majeure event affects the performance of any work that is on the critical path of the work and causes, or will cause, the tank contractor to complete the work beyond the applicable milestone date. The tank contractor is also entitled to its reasonable incremental costs incurred as a result of aforce majeure event, but only after such costs incurred with respect to any oneforce majeure event exceed $250,000.

Aforce majeure under the tank contract is any act or event that:

• prevents, delays or materially and adversely impacts the affected party’s performance of its obligations in accordance with the terms of the tank contract;

• is beyond the reasonable control of the affected party, not due to its fault or negligence; and

• could not have been prevented or avoided by the affected party through the exercise of commercially reasonable efforts.

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The tank contractor may terminate the tank contract upon 30 days’ prior written notice if aforce majeure event causes a complete suspension of all work that continues for more than 120 consecutive days, unless we agree to a modification of the contract price and modifying the milestone schedule to account for suchforce majeure event.

Termination and Suspension

We have the right to terminate the tank contract as a result of a default by the tank contractor, which occurs if the tank contractor:

• performs work that fails materially to conform to the requirements of the tank contract;

• fails to make progress according to the agreed-upon tank contract schedule so as to endanger performance of the tank contract;

• abandons or refuses to proceed with any of the work, including modifications thereto;

• fails to fulfill or comply with any of the other material terms of the tank contract;

• fails to commence the work in accordance with the provisions of the tank contract;

• abandons the work;

• fails to maintain insurance required under the tank contract;

• materially disregards applicable law or applicable standards and codes;

• engages in behavior that is dishonest, fraudulent or constitutes a conflict with the tank contractor’s obligations under the tank contract; or

• suffers an insolvency event or makes a general assignment for the benefit of creditors.

In the event of such a default (other than such set forth in the last bullet, in which case we have an immediate right to terminate the tank contract) which remains uncured after 30 days’ notice (or a reasonable time beyond 30 days, not to exceed 90 days), we may:

• terminate the tank contract in whole or in part;

• complete the work in whatever manner we deem expedient;

• take possession of and utilize any data, designs, work product, licenses, materials, equipment and tools furnished by the tank contractor or subcontractors or sub-subcontractors and necessary to complete the work;

• hire any or all of the tank contractor’s employees; and

• take assignment of any or all of the subcontracts and sub-subcontracts.

Notwithstanding the foregoing, we are not entitled to terminate the tank contract for delay in achieving mechanical completion for a Phase 2 – Stage 1 tank during the first three months after the milestone date for the tank unless the tank contractor is not paying our liquidated damages when owed during such three-month period or the tank contractor is not diligently performing the work, and we are otherwise entitled to terminate the tank contract.

Following such termination, if the cost to complete the Phase 2 – Stage 1 tanks exceeds the unpaid balance of the contract price, the tank contractor will be liable for the difference. In addition, the tank contractor is also liable for liquidated damages and the cost to accelerate the work of any substitute contractor to achieve the milestone dates. All such liabilities are subject to the limitations on liquidated damages and total liabilities described above.

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We have the right to terminate the tank contract in whole or in part for convenience by written notice to the tank contractor. In such event, the tank contractor will be paid:

• the portion of the contract price for the work performed prior to termination, less that portion of the contract price paid previously;

• all reasonable costs for work thereafter performed as specified in such notice;

• reasonable administrative costs of settling and paying claims arising out of the termination of work under subcontracts and sub-subcontracts;

• reasonable costs associated with demobilization;

• a reasonable overhead and profit on the amounts;

• a sum equal to 5% of the unpaid contract price, not to exceed $4,000,000; and

• less all payments previously made.

If we fail to pay any undisputed amount due and owing to the tank contractor and such failure continues for more than 30 days after the due date for such payment, then the tank contractor may suspend performance of the work until the tank contractor receives such undisputed amounts. If we do not cure such failure within 30 days after receipt of the notification given above, or fail to provide satisfactory evidence that such default will be corrected within 90 days, the tank contractor may, by written notice to us, terminate in whole or in part the tank contract.

We may, upon written notice, suspend all or any portion of the work. The tank contractor is permitted to submit a change order to recover the reasonable costs of such suspension. The tank contractor has no equivalent right to terminate or suspend the tank contract.

Phase 2 – Stage 1 EPC LNG Soil Contract

Scope of Work

In July 2006, we entered into an Engineer, Procure and Construct (EPC) LNG Unit Rate Soil Contract, or the soil contract, with Recon, or the soil contractor, for Phase 2 – Stage 1 of our LNG receiving terminal expansion project. Under the soil contract, the soil contractor 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 otherwise set forth in the soil contract.

Payments

Upon issuing the NTP, we paid the soil contractor an initial payment of $2,850,000. 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. As retainage, we withhold 10% of each invoiced amount, with the retainage being released upon final completion of the work.

In addition to disputed invoice amounts, we may, upon giving prior written notice and allowing the soil contractor an opportunity to cure, withhold payment on an invoice or a portion thereof, or collect on the letter of credit, if:

• the soil contractor is in default of any soil contract condition, including, but not limited to, the schedule, quality assurance and health and safety requirements;

• the soil contractor has not submitted the soil contract schedule, including any revisions or updates, as required by the soil contract;

• the soil contractor has failed to submit proper insurance certificates, or not provided proper coverage or proof thereof;

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• the soil contractor fails to submit interim lien waivers from the soil contractor and major subcontractors; or

• adjustments are due from previous overpayment or audit results.

Letter of Credit

The soil contractor has furnished us with an irrevocable standby letter of credit in an amount of $2,850,000, issued by a bank acceptable to us. The letter of credit will expire upon final completion of the work. If at any time the unit rates are increased by change order by more than 10% of the unit rates, upon our request, the soil contractor will increase the amount of the letter of credit to 10% of the adjusted unit rates.

Change Orders

We have the right to submit any change order to make any change in the work that is within the scope of the soil contract.

The soil contractor has the right to submit a change order in the event of specified circumstances, including the following:

• a change in law;

• acts or omissions by us that constitute a change in the work under the soil contract;

• force majeure;

• acceleration of the work directed by us;

• in the event of a delay or suspension of work ordered by us;

• in the event subsurface soil conditions are materially different from the information provided by us; and

• discovery of pre-existing hazardous material at the site.

In many instances, before such a change order can be submitted by the soil contractor, such occurrences must adversely affect the soil contractor’s (i) ability to perform the work in accordance with the project schedule; or (ii) ability to perform any material obligation under the soil contract.

Liquidated Damages

The soil contractor is required to pay liquidated damages for each day of delay that the soil contractor fails to achieve substantial completion for each Phase 2 – Stage 1 tank and final completion by the respective specified milestone date. The amount of the liquidated damages for failure to achieve the milestone date for substantial completion and final completion of each tank is $21,000 for each day of delay, subject in all cases to a maximum of $3,000,000.

Limitation of Liabilities

The soil contractor is obligated to perform all of the work required to achieve substantial completion. Following attainment of substantial completion, liability under the soil contract or under any cause of action related to the subject matter of the soil contract, whether in contract, warranty, tort, strict liability, products liability, professional liability, indemnity, contribution or any other cause of action, is limited to an aggregate of $7,500,000, except that this limitation does not apply to: (i) losses caused by intentional misconduct or gross negligence of the soil contractor; (ii) the soil contractor’s indemnification obligations under the soil contract; or (iii) proceeds of insurance required to be obtained by the soil contractor and its subcontractors and sub-subcontractors.

Warranty

The soil contractor warrants that the work (including all materials and equipment) will be new (unless otherwise agreed) and of good quality, in accordance with all requirements of the soil contract (including good

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engineering and construction practices, applicable law and applicable codes and standards), and free from encumbrances to title. Until the end of the defect correction period (ending 24 months after substantial completion, subject to extension to 36 months where corrective work is performed), the soil contractor is liable to promptly correct any work that is found defective.

Force Majeure

Aforce majeure event entitles the soil contractor to an extension to the project schedule if the delay caused by theforce majeure event affects the performance of any work that is on the critical path of the work and causes, or will cause, the soil contractor to complete the work beyond the applicable milestone date. Aforce majeure under the soil contract is any act or event that:

• prevents or delays the affected party’s performance of its obligations in accordance with the terms of the soil contract;

• is beyond the reasonable control of the affected party, not due to its fault or negligence; and

• could not have been prevented or avoided by the affected party through the exercise of due diligence.

If there is aforce majeure event, the soil contractor shall be entitled to an extension of the applicable milestone date, which is the soil contractor’s sole remedy for the occurrence of such delay for a continuous period of less than 30 days. For such an event that extends beyond 30 consecutive days, the soil contractor may be entitled to an adjustment to the unit rates for reimbursement of the standby time for the soil contractor’s employees and construction equipment and other standby costs that are incurred by the soil contractor after the expiration of such 30-day period and which are caused by such excusable delay, up to a maximum aggregate of 40 days of standby time.

Termination and Suspension

We have the right to terminate the soil contract as a result of a default by the soil contractor, which occurs if the soil contractor:

• performs work which fails materially to conform to the requirements of the soil contract;

• fails to make progress so as to endanger performance of the soil contract;

• abandons or refuses to proceed with any of the work, including modifications thereto;

• fails to fulfill or comply with any of the terms of the soil contract;

• fails to commence the work in accordance with the provisions of the soil contract;

• abandons the work;

• fails to maintain insurance required under the soil contract;

• materially disregards applicable law or applicable standards and codes;

• engages in behavior that is dishonest, fraudulent or constitutes a conflict with the soil contractor’s obligations under the soil contract; or

• suffers an insolvency event or makes a general assignment for the benefit of creditors.

In the event of such a default (other than such set forth in the last bullet, which provides an immediate right of termination, or a default considered not curable or for failure to cure safety violations) which remains uncured after 48 hours’ notice (or a reasonable time beyond 48 hours, not to exceed 30 days), we may:

• terminate the soil contract in whole or in part;

• complete the work in whatever manner we deem expedient;

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• take possession of and utilize any data, designs, work product, licenses, materials, plant, equipment, tools and property of any kind furnished by the soil contractor or subcontractors or sub-subcontractors and necessary to complete the work;

• hire any or all of the soil contractor’s employees; and

• take assignment of any or all of the subcontracts and sub-subcontracts.

Following such termination, the soil contractor will be liable for liquidated damages and the cost of any substitute contractor to accelerate the work in order to achieve the substantial completion milestone dates, subject to the limitations on liquidated damages and total liabilities described above.

We have the right to terminate the soil contract in whole or in part for convenience by written notice to the soil contractor. In this event, the soil contractor will be paid:

• the unit rates corresponding to the work performed prior to termination;

• all reasonable costs for work thereafter performed as specified in such notice;

• reasonable administrative costs of settling and paying claims arising out of the termination of work under subcontracts and sub-subcontracts;

• reasonable costs incurred in demobilization and the disposition of residual material, plant and equipment;

• a sum equal to 5% of the result obtained by subtracting all previous payments to the soil contractor from $30,000,000, but such sum shall not in any event exceed $1,000,000; and

• less all payments previously made.

We may, upon written notice, suspend all or any portion of the work. The soil contractor is permitted to submit a change order to recover the reasonable costs of such suspension. The soil contractor has no equivalent right to terminate or suspend the soil contract.

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MANAGEMENT

Directors and Executive Officers of Our General Partner

We have no employees, directors or officers. We are managed by our general partner, Sabine Pass LNG GP. The following sets forth information, as of May 29, 2007, regarding the individuals who currently serve on the board of directors and as officers of our general partner.

Name	Age	Position with Our General Partner
Charif Souki	54	Director
Stanley C. Horton	57	Director and Chief Executive Officer
Keith G. Little	49	President
Don A. Turkleson	52	Chief Financial Officer
Victor Duva	48	Director

Charif Souki is a director of our general partner. Mr. Souki, a co-founder of Cheniere, is Chairman of Cheniere’s board of directors and Chief Executive Officer of Cheniere. Since December 2002, Mr. Souki has been the Chief Executive Officer of Cheniere and he was also President of Cheniere from that time until April 2005. From June 1999 to December 2002, he was Chairman of the board of directors of Cheniere and an independent investment banker. From September 1997 until June 1999, Mr. Souki was co-chairman of the board of directors of Cheniere, and he served as Secretary of Cheniere from July 1996 until September 1997. Mr. Souki has over 20 years of independent investment banking experience in the industry and has specialized in providing financing for small capitalization companies with an emphasis on the oil and gas industry. Mr. Souki received a B.A. from Colgate University and an M.B.A. from Columbia University.

Stanley C. Horton is a director and Chief Executive Officer of our general partner. Mr. Horton is President and Chief Operating Officer of Cheniere. He has over 30 years of experience in the natural gas and energy industry. From November 2004 to April 2005, when he joined Cheniere, Mr. Horton served as President and Chief Operating Officer of Panhandle Energy, an owner and operator of 18,000 miles of interstate pipelines and the Lake Charles LNG receiving terminal. From June 2003 until November 2004, he was President and Chief Executive Officer of CrossCountry Energy, which holds interests in and operates natural gas pipeline businesses. From 1997 to June 2003, Mr. Horton was Chairman and Chief Executive Officer of Enron Transportation Services which had responsibility for all of Enron’s North American interstate natural gas pipeline and transmission line companies. Mr. Horton was Chairman and Chief Executive Officer of EOTT Energy Corp., the general partner of EOTT Energy Partners, L.P., prior to the bankruptcy filings of those entities in October 2002. Mr. Horton currently serves on the Board of Directors for the Interstate Natural Gas Association of America and was its Chairman in 2001. He also has chaired the Gas Industry Standards Board (2000) and the Natural Gas Council (2002). He previously served on the Board of Directors of Portland General Electric, an electric utility, and the Board of Directors of Elektro Eletricidade e Serviços S.A., a local electricity distribution company in Sao Paolo, Brazil. Mr. Horton received a B.S. in finance from the University of Florida and an M.S. in management from Rollins College.

Keith G. Little is the President of our general partner. Mr. Little has served as Vice President—Business Development of Cheniere LNG, Inc. since June 2005 where he has led the development of the Sabine Pass and Creole Trail LNG receiving terminals in Cameron Parish, Louisiana. Prior to joining Cheniere, Mr. Little worked for more than 20 years for ConocoPhillips in a variety of business development, finance and strategic planning roles in the upstream, downstream and corporate sectors. His business development work focused on midstream gas and power projects in the U.S. Gulf Coast, the North Sea and emerging markets. Mr. Little led ConocoPhillips’ participation in the Freeport LNG receiving terminal project, in which Cheniere holds a 30%

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limited partner interest. Mr. Little received a B.A. in math and economics from Swarthmore College and an MBA with a concentration in finance from the University of Chicago.

Don A. Turkleson is Chief Financial Officer of our general partner. Mr. Turkleson is Senior Vice President and Chief Financial Officer of Cheniere. He became a Senior Vice President of Cheniere in May 2004, relinquished the position of Treasurer of Cheniere in December 2004 and relinquished the position of Secretary in September 2006. He had served as Vice President, Chief Financial Officer, Secretary and Treasurer of Cheniere since December 1997. Prior to joining Cheniere in 1997, Mr. Turkleson was employed by PetroCorp Incorporated from 1983 to 1996, as Controller until 1986, then as Vice President—Finance, Secretary and Treasurer. From 1975 to 1983, he worked as a Certified Public Accountant in the natural resources division of Arthur Andersen & Co. in Houston. Mr. Turkleson received a B.S. in accounting from Louisiana State University. He is a director and past Chairman of the Board of Neighborhood Centers, Inc., a nonprofit organization.

Victor Duva serves as an independent director of our general partner. Mr. Duva has been the President of C T Corporate Staffing, Inc. since 2003. Between 1981 and 2003, Mr. Duva has held various positions with C T Corporate Staffing, Inc., including Account Representative, Assistant Vice President/Office Manager of two offices and Business Process Analyst. He received his B.A. at St. Thomas of Villanova University.

Governance and Management

Except for Mr. Duva, the individuals who serve on the board of directors and as officers of our general partner also serve as executive officers and/or directors of other affiliated entities, including Cheniere and direct or indirect subsidiaries of Cheniere. Each of our general partner’s directors and officers spent less than a majority of his or her time on our business in 2006.

As long as any of the notes remain outstanding, our general partner must have at least one director who is not, and for at least five years preceding such appointment has not been, a stockholder, director, manager, officer, trustee, employee, partner, member, attorney, counsel, creditor, customer or supplier of us, our general partner or any of our respective affiliates and who does not and has not had specified financial relationships with us, our general partner or any of our respective affiliates. We refer to this person as an independent director, and any such person may not control, be under common control with or be a member of the immediate family of any person excluded from serving as an independent director.

Our and our general partner’s organizational documents require that any voluntary filing under bankruptcy or insolvency laws by the general partner on its own behalf or on behalf of us must be approved by the entire board of directors of our general partner, including the independent director. Our and our general partner’s organizational documents also contain limitations on the ability to (i) guaranty third-party obligations (including those of any affiliates), (ii) incur, create or assume indebtedness and (iii) consolidate, merge, sell or otherwise transfer any assets outside the ordinary course of business. In addition, we and our general partner are also subject to prohibitions on, among other actions, (x) the ability to engage in any business other than as contemplated in our organizational documents, (y) any dissolution or liquidation and (z) any amendment, modification or change to the single purpose entity requirements set forth in our organizational documents.

We and our general partner are also required to observe certain “separateness” covenants designed to maintain each of our existences as separate legal entities distinct from any other entity. For example, we and our general partner are each required, among other things, to (i) maintain separate books, records and bank accounts, (ii) maintain separate financial statements subject to certain exceptions, (iii) prepare and file our own tax returns separate from those of any other person to the extent required by law, (iv) enter into transactions with affiliates on an arms-length basis (or on terms that are fair if no comparable transactions with unaffiliated third parties would be available), (v) not commingle our accounts or funds with those of another person, (vi) pay our liabilities and expenses out of and to the extent of our own funds and (vii) maintain a sufficient number of employees or engage affiliated or independent contractors in light of our contemplated business purpose.

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Compensation

Our general partner was formed in October 2003. Our general partner has paid no compensation to its directors and officers since inception and has no plans to do so in the future, except that Mr. Duva is compensated $2,300 per year for serving as its independent director. Officers and employees, if any, of the general partner may participate in employee benefit plans and arrangements sponsored by Cheniere and its affiliates, including plans that may be established by Cheniere and its affiliates in the future.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

We are significantly dependent on Cheniere and its affiliates and our general partner and have numerous contractual and commercial relationships and conflicts of interests with them. Please read “Risk Factors” for a more thorough explanation of these commercial and contractual relationships and the conflicts of interest related thereto. The board of directors of our general partner has the responsibility, under the terms of our partnership agreement, to review and approve all transactions or series of related financial transactions, arrangements or relationships between us and any related party if the amount involved exceeds $120,000. We do not otherwise have any policies or procedures for the review, approval or ratification of any such transactions.

Cheniere Marketing TUA

In November 2006, we entered into an amended and restated TUA with Cheniere Marketing for the reservation of 2.0 Bcf/d of regasification capacity at our LNG receiving terminal. See “Business—Customers—Cheniere Marketing TUA.”

Sabine Pass LNG Operation and Maintenance Agreement

In February 2005, we 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 has agreed to provide all necessary services required to construct, operate and maintain our 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, we are 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 in certain circumstances be entitled to a bonus equal to 50% of the salary component of labor costs. In addition, we are required to reimburse O&M Services for our operating expenses, which consist of labor, maintenance, land lease and insurance expenses, and for maintenance capital expenditures. Approval of this agreement was negotiated with the lenders under our then-existing credit facility and, because we did not otherwise ascertain market terms, may not be on terms as favorable to us as we could have obtained from an unaffiliated third party. Pursuant to the O&M Agreement, we paid O&M Services $868,571 for services provided during 2005, $1,140,000 for services provided during 2006 and $285,000 for services provided during the first quarter of 2007.

In March 2007, O&M Services assigned the O&M Agreement to Cheniere Energy Partners GP, LLC, or Cheniere Energy Partners GP, and O&M Services and Cheniere Energy Partners GP entered into a services and secondment agreement pursuant to which certain employees of O&M Services have been seconded to Cheniere Energy Partners GP to provide operating and routine maintenance services with respect to our LNG receiving terminal under the direction, supervision and control of Cheniere Energy Partners GP. Under this agreement, Cheniere Energy Partners GP will pay O&M Services the amounts that it receives from us under the O&M Agreement. The services and secondment agreement will remain in effect until the O&M Agreement is terminated; however, Cheniere Energy Partners GP may terminate the agreement upon 30 days written notice.

Sabine Pass LNG Management Services Agreement

In February 2005, we entered into a Management Services Agreement, or the Sabine Pass LNG MSA, with our general partner, which is also a subsidiary of Cheniere. Pursuant to the Sabine Pass LNG MSA, we appointed our general partner to manage the construction and operation of our 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 our LNG receiving facility, we are required to pay our 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). Approval of this agreement was negotiated with the lenders under our then-existing credit facility and, because we did not otherwise ascertain market terms, may not be on terms as favorable to us as we could have obtained from an unaffiliated third party. Pursuant to the Sabine Pass LNG MSA, we paid our general partner $3,109,000 for services provided during 2005, $4,080,000 for services provided during 2006 and $1,020,000 for services provided during the first quarter of 2007.

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General Partner Management Services Agreement

In September 2006, our general partner entered into a Management Services Agreement, or the general partner MSA, with Cheniere LNG Terminals, Inc., or Terminals, a wholly-owned subsidiary of Cheniere. Pursuant to the general partner MSA, Terminals provides to the general partner the technical, financial, staffing and related support necessary to allow our general partner to meet its obligations to us under the Sabine Pass LNG MSA. Under the general partner MSA, our general partner will pay Terminals amounts that it receives from us for management of our LNG receiving terminal. Because this is a pass-through agreement, it may not be on terms as favorable to us as we could have obtained from an unaffiliated third party. During 2006 and the first quarter of 2007, our general partner incurred $1,360,000 and $1,020,000, respectively, under the general partner MSA.

Assumption Agreement

Under a settlement agreement dated as of June 14, 2001, Cheniere and affiliated entities engaged in the LNG business, including our partnership, have agreed to pay a royalty, which we refer to as the Crest Royalty. The Crest Royalty is calculated based on the volume of natural gas processed through covered LNG facilities and is subject to a maximum of $10.95 million per production year beginning when natural gas is first commercially processed through a covered facility.

We do not expect to pay any Crest Royalty amounts at any time for two reasons:

• Freeport LNG, L.P., in which Cheniere holds a 30% limited partner interest and which we refer to as Freeport LNG, has assumed the obligation to pay the Crest Royalty based on natural gas processed at Freeport LNG’s receiving terminal. The maximum annual Crest Royalty payment of $10.95 million per contract year is payable if approximately 1.0 Bcf/d is processed. Freeport LNG has entered into TUAs with ConocoPhillips Company and with The Dow Chemical Company, under which capacity payments begin when the Freeport LNG receiving terminal begins commercial operation. The ConocoPhillips TUA reserves capacity of approximately 0.5 Bcf/d initially and increases to 1.0 Bcf/d in October 2009. The Dow TUA reserves capacity of approximately 0.5 Bcf/d. Freeport LNG has announced that it expects to commence commercial operation in 2008.

• Our ultimate parent company, Cheniere, has agreed to indemnify us against any Crest Royalty obligation and to pay any Crest Royalty amounts that may be due and not paid by Freeport LNG.

As agreed in the 2001 settlement agreement, Cheniere and affiliated entities engaged in the LNG business, including our partnership, have each entered into an agreement, which we refer to as the Assumption Agreement, under which we each have assumed and adopted the Crest Royalty obligation and have agreed not to create any non-permitted lien, security interest or other encumbrance for borrowed money that is senior to orpari passu with the Crest Royalty obligation. In accordance with this agreement, the payment of any Crest Royalty amount that we may become obligated to pay will be secured by the same collateral as, and payable prior to any payments in respect of, the notes.

Arrangements Regarding Taxes

In November 2006, we entered into a State Tax Sharing Agreement with Cheniere pursuant to which Cheniere has agreed to prepare and file all Texas franchise tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined tax liability. If Cheniere, in its sole discretion, demands such payment, we will pay to Cheniere an amount equal to the Texas franchise tax that we would be required to pay if our Texas franchise tax liability were computed on a separate company basis. The State Tax Sharing Agreement contains similar provisions for other state and local taxes required to be filed by Cheniere and our partnership on a combined, consolidated or unitary basis. The State Tax Sharing Agreement is effective for tax returns first due on or after January 1, 2008.

We will also make distributions to our partners in respect of federal, state and local income taxes not covered by the State Tax Sharing Agreement in respect of periods in which we and any of our subsidiaries are treated as pass-through entities for federal and state income tax purposes. See “Description of Notes—Certain Definitions—Permitted Payments to Parent.”

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The limited partner interest in our partnership is divided into units. The following table sets forth the beneficial ownership of our units owned of record and beneficially as of May 29, 2007:

• each person who beneficially owns more than 5% of the units;

• each of the directors of our general partner;

• each of the named executive officers of our general partner; and

• all directors and executive officers of our general partner as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Cheniere Energy, Inc., as the ultimate parent of Sabine Pass LNG-LP, LLC, has voting and investment control over our units. The address for the beneficial owner listed below is 700 Milam Street, Suite 800, Houston, Texas 77002.

Name of Beneficial Owner	Units Beneficially Owned	Percentage of Total Units Beneficially Owned
Sabine Pass LNG-LP, LLC	100	100	%
Sabine Pass LNG-GP, Inc.(1)	—	—
Charif Souki	—	—
Stanley C. Horton	—	—
Keith G. Little	—	—
Don A. Turkleson	—	—
Victor Duva	—	—
All executive officers and directors as a group (7 persons)	—	—

(1) Sabine Pass LNG-GP, Inc. is our sole general partner. It holds all of our general partner interest and controls us. It has no economic interest in us. It has sole voting and investment power with respect to its general partner interest in us.

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THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

On November 9, 2006, we sold $2,032 million in aggregate principal amount at maturity of the initial notes in a private placement. The initial notes were sold to the initial purchasers who in turn resold the notes to a limited number of qualified institutional buyers and foreign investors pursuant to Rule 144A and Regulation S of the Securities Act, respectively.

In connection with the sale of the initial notes, we entered into a registration rights agreement with the representative of the initial purchasers of the initial notes, pursuant to which we agreed to file and to use all commercially reasonable efforts to cause to be declared effective by the SEC a registration statement with respect to the exchange of the initial notes for the notes. We are making the exchange offer to fulfill our contractual obligations under that agreement. A copy of the registration rights agreement has been filed as an exhibit to the registration statement of which this prospectus is a part.

Pursuant to the exchange offer, we will issue the notes in exchange for initial notes. The terms of the notes are identical in all material respects to those of the initial notes, except that the notes (1) have been registered under the Securities Act and therefore will not be subject to certain restrictions on transfer applicable to the initial notes and (2) will not have registration rights or provide for any liquidated damages related to the obligation to register. Please read “Description of Notes” for more information on the terms of the respective notes and the differences between them.

We are not making the exchange offer to, and will not accept tenders for exchange from, holders of initial notes in any jurisdiction in which an exchange offer or the acceptance thereof would not be in compliance with the securities or blue sky laws of such jurisdiction. Unless the context requires otherwise, the term “holder” with respect to the exchange offer means any person in whose name the initial notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder, or any person whose initial notes are held of record by The Depository Trust Company, referred to as DTC, who desires to deliver such initial notes by book-entry transfer at DTC.

We make no recommendation to the holders of initial notes as to whether to tender or refrain from tendering all or any portion of their initial notes pursuant to the exchange offer. In addition, no one has been authorized to make any such recommendation. Holders of initial notes must make their own decision whether to tender pursuant to the exchange offer and, if so, the aggregate amount of initial notes to tender after reading this prospectus and the letter of transmittal and consulting with the advisers, if any, based on their own financial position and requirements.

In order to participate in the exchange offer, you must represent to us, among other things, that:

• you are acquiring the notes in the exchange offer in the ordinary course of your business;

• you are not engaged in, and do not intend to engage in, a distribution of the notes;

• you do not have and to your knowledge, no one receiving notes from you has, any arrangement or understanding with any person to participate in the distribution of the notes;

• you are not a broker-dealer tendering initial notes acquired directly from us for your own account or if you are a broker-dealer, you will comply with the prospectus delivery requirements of the Securities Act in connection with any resale of the notes; and

• you are not one of our “affiliates,” as defined in Rule 405 of the Securities Act.

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Each broker-dealer that receives notes for its own account in exchange for initial notes, where such initial notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such notes. Please read “Plan of Distribution.”

Terms of Exchange

Upon the terms and conditions described in this prospectus and in the accompanying letter of transmittal, which together constitute the exchange offer, we will accept for exchange initial notes that are properly tendered at or before the expiration time and not withdrawn as permitted below. As of the date of this prospectus, $550 million aggregate principal amount of 7 ¹/4% Senior Secured Notes due 2013 and $1,482 million aggregate principal amount of 7 ¹/2% Senior Secured Notes due 2016 are outstanding. This prospectus, together with the letter of transmittal, is first being sent on or about the date on the cover page of the prospectus to all holders of initial notes known to us. Initial notes tendered in the exchange offer must be in denominations of principal amount of $100,000 and any integral multiple of $1,000.

Our acceptance of the tender of initial notes by a tendering holder will form a binding agreement between the tendering holder and us upon the terms and subject to the conditions provided in this prospectus and in the accompanying letter of transmittal.

The form and terms of the notes being issued in the exchange offer are the same as the form and terms of the initial notes except that:

• the notes being issued in the exchange offer will have been registered under the Securities Act;

• the notes being issued in the exchange offer will not bear the restrictive legends restricting their transfer under the Securities Act; and

• the notes being issued in the exchange offer will not contain the registration rights contained in the initial notes.

Expiration, Extension and Amendment

The expiration time of the exchange offer is 5:00 p.m., New York City time, on [                    ]. However, we may, in our sole discretion, extend the period of time for which the exchange offer is open and set a later expiration date for the offer. The term “expiration time” as used herein means the latest time and date to which we extend the exchange offer. If we decide to extend the exchange offer period, we will then delay acceptance of any initial notes by giving oral or written notice of an extension to the holders of initial notes as described below. During any extension period, all initial notes previously tendered will remain subject to the exchange offer and may be accepted for exchange by us. Any initial notes not accepted for exchange will be returned to the tendering holder after the expiration or termination of the exchange offer.

Our obligation to accept initial notes for exchange in the exchange offer is subject to the conditions described below under “—Conditions to the Exchange Offer.” We may decide to waive any of the conditions in our discretion. Furthermore, we reserve the right to amend or terminate the exchange offer, and not to accept for exchange any initial notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer specified below under the same heading. We will give oral or written notice of any extension, amendment, non–acceptance or termination to the holders of the initial notes as promptly as practicable. If we materially change the terms of the exchange offer, we will resolicit tenders of the initial notes, file a post–effective amendment to the prospectus and provide notice to you. If the change is made less than five business days before the expiration of the exchange offer, we will extend the offer so that the holders have at least five business days to tender or withdraw. We will notify you of any extension by means of a press release or other public announcement no later than 9:00 a.m., New York City time, on the first business day after the previously scheduled expiration time.

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Procedures for Tendering

Valid Tender

Except as described below, a tendering holder must, prior to the expiration time, transmit to The Bank of New York, the exchange agent, at the address listed below under the caption “—Exchange Agent”:

• a properly completed and duly executed letter of transmittal, including all other documents required by the letter of transmittal; or

• if initial notes are tendered in accordance with the book–entry procedures listed below, an agent’s message transmitted through DTC’s Automated Tender Offer Program, referred to as ATOP.

In addition, you must:

• deliver certificates, if any, for the initial notes to the exchange agent at or before the expiration time; or

• deliver a timely confirmation of the book–entry transfer of the initial notes into the exchange agent’s account at DTC, the book–entry transfer facility, along with the letter of transmittal or an agent’s message; or

• comply with the guaranteed delivery procedures described below.

The term “agent’s message” means a message, transmitted by DTC to, and received by, the exchange agent and forming a part of a book–entry confirmation, that states that DTC has received an express acknowledgment that the tendering holder agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against such holder.

If the letter of transmittal is signed by a person other than the registered holder of initial notes, the letter of transmittal must be accompanied by a written instrument of transfer or exchange in satisfactory form duly executed by the registered holder with the signature guaranteed by an eligible institution. The initial notes must be endorsed or accompanied by appropriate powers of attorney. In either case, the initial notes must be signed exactly as the name of any registered holder appears on the initial notes.

If the letter of transmittal or any initial notes or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys–in–fact, officers of corporations or others acting in a fiduciary or representative capacity, these persons should so indicate when signing. Unless waived by us, proper evidence satisfactory to us of their authority to so act must be submitted.

By tendering, each holder will represent to us that, among other things, the person is not our affiliate, the notes are being acquired in the ordinary course of business of the person receiving the notes, whether or not that person is the holder, and neither the holder nor the other person has any arrangement or understanding with any person to participate in the distribution of the notes. Each broker-dealer that receives notes for its own account in exchange for initial notes, where such initial notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such notes. Please read “Plan of Distribution.”

The method of delivery of initial notes, letters of transmittal and all other required documents is at your election and risk, and the delivery will be deemed made only upon actual receipt or confirmation by the exchange agent. If the delivery is by mail, we recommend that you use registered mail, properly insured, with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery. Holders tendering through DTC’s ATOP system should allow sufficient time for completion of the ATOP procedures during the normal business hours of DTC on such dates.

No initial notes, agent’s messages, letters of transmittal or other required documents should be sent to us. Delivery of all initial notes, agent’s messages, letters of transmittal and other documents must be made to the

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exchange agent. Holders may also request their respective brokers, dealers, commercial banks, trust companies or nominees to effect such tender for such holders.

If you are a beneficial owner whose initial notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and wish to tender, you should promptly instruct the registered holder to tender on your behalf. Any registered holder that is a participant in DTC’s ATOP system may make book–entry delivery of the initial notes by causing DTC to transfer the initial notes into the exchange agent’s account. The tender by a holder of initial notes, including pursuant to the delivery of an agent’s message through DTC’s ATOP system, will constitute an agreement between such holder and us in accordance with the terms and subject to the conditions set forth herein and in the letter of transmittal.

All questions as to the validity, form, eligibility, time of receipt and withdrawal of the tendered initial notes will be determined by us in our sole discretion, which determination will be final and binding. We reserve the absolute right to reject any and all initial notes not validly tendered or any initial notes which, if accepted, would, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any irregularities or conditions of tender as to particular initial notes. Our interpretation of the terms and conditions of this exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of initial notes must be cured within such time as we shall determine. Although we intend to notify you of defects or irregularities with respect to tenders of initial notes, none of us, the exchange agent, or any other person shall be under any duty to give notification of defects or irregularities with respect to tenders of initial notes, nor shall any of them incur any liability for failure to give such notification. Tenders of initial notes will not be deemed to have been made until such irregularities have been cured or waived. Any initial notes received by the exchange agent that are not validly tendered and as to which the defects or irregularities have not been cured or waived will be returned without cost to such holder by the exchange agent, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date of the exchange offer.

Although we have no present plan to acquire any initial notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any initial notes that are not tendered in the exchange offer, we reserve the right, in our sole discretion, to purchase or make offers for any initial notes after the expiration date of the exchange offer, from time to time, through open market or privately negotiated transactions, one or more additional exchange or tender offers, or otherwise, as permitted by law, the indenture and our other debt agreements. Following consummation of this exchange offer, the terms of any such purchases or offers could differ materially from the terms of this exchange offer.

Signature Guarantees

Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed, unless the initial notes surrendered for exchange are tendered:

• by a registered holder of the initial notes who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal; or

• for the account of an “eligible institution.”

If signatures on a letter of transmittal or a notice of withdrawal are required to be guaranteed, the guarantees must be by an “eligible institution.” An “eligible institution” is an “eligible guarantor institution” meeting the requirements of the registrar for the notes within the meaning of Rule 17Ad-15 under the Securities Exchange Act of 1934, as amended, or the Exchange Act.

Book-Entry Transfer

The exchange agent will make a request to establish an account for the initial notes at DTC for purposes of the exchange offer. Any financial institution that is a participant in DTC’s system may make book–entry delivery

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of initial notes by causing DTC to transfer those initial notes into the exchange agent’s account at DTC in accordance with DTC’s procedure for transfer. The participant should transmit its acceptance to DTC at or prior to the expiration time or comply with the guaranteed delivery procedures described below. DTC will verify this acceptance, execute a book–entry transfer of the tendered initial notes into the exchange agent’s account at DTC and then send to the exchange agent confirmation of this book–entry transfer. The confirmation of this book–entry transfer will include an agent’s message confirming that DTC has received an express acknowledgment from this participant that this participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this participant.

Delivery of notes issued in the exchange offer may be effected through book–entry transfer at DTC. However, the letter of transmittal or facsimile of it or an agent’s message, with any required signature guarantees and any other required documents, must:

• be transmitted to and received by the exchange agent at the address listed under “—Exchange Agent” at or prior to the expiration time; or

• comply with the guaranteed delivery procedures described below.

Delivery of documents to DTC in accordance with DTC’s procedures does not constitute delivery to the exchange agent.

Guaranteed Delivery

If a registered holder of initial notes desires to tender the initial notes, and the initial notes are not immediately available, or time will not permit the holder’s initial notes or other required documents to reach the exchange agent before the expiration time, or the procedures for book–entry transfer described above cannot be completed on a timely basis, a tender may nonetheless be made if:

• the tender is made through an eligible institution;

• prior to the expiration time, the exchange agent receives by facsimile transmission, mail or hand delivery from such eligible institution a properly and validly completed and duly executed notice of guaranteed delivery, substantially in the form provided by us:

• stating the name and address of the holder of the initial notes and the amount of initial notes tendered,

• stating that the tender is being made, and

• guaranteeing that within three New York Stock Exchange trading days after the expiration time, the certificates for all physically tendered initial notes, in proper form for transfer, or a book–entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

• the certificates for all physically tendered initial notes, in proper form for transfer, or a book–entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and all other documents required by the letter of transmittal, are received by the exchange agent within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery.

Determination of Validity

We will determine in our sole discretion all questions as to the validity, form and eligibility of initial notes tendered for exchange. This discretion extends to the determination of all questions concerning the timing of receipts and acceptance of tenders. These determinations will be final and binding. We reserve the right to reject

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any particular initial note not properly tendered or of which our acceptance might, in our judgment or our counsel’s judgment, be unlawful. We also reserve the right to waive any defects or irregularities or conditions of the exchange offer as to any particular initial note either before or after the expiration time, including the right to waive the ineligibility of any tendering holder. Our interpretation of the terms and conditions of the exchange offer as to any particular initial note either before or after the applicable expiration time, including the letter of transmittal and the instructions to the letter of transmittal, shall be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of initial notes must be cured within a reasonable period of time.

Neither we, the exchange agent nor any other person will be under any duty to give notification of any defect or irregularity in any tender of initial notes. Moreover, neither we, the exchange agent nor any other person will incur any liability for failing to give notifications of any defect or irregularity.

Acceptance of Initial Notes for Exchange; Issuance of Notes

Upon the terms and subject to the conditions of the exchange offer, we will accept, promptly after the expiration time, all initial notes properly tendered. We will issue the notes promptly after acceptance of the initial notes. For purposes of an exchange offer, we will be deemed to have accepted properly tendered initial notes for exchange when, as and if we have given oral or written notice to the exchange agent, with prompt written confirmation of any oral notice.

For each initial note accepted for exchange, the holder will receive a new note registered under the Securities Act having a principal amount equal to that of the surrendered initial note. As a result, registered holders of initial notes issued in the exchange offer on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid on the initial notes or, if no interest has been paid on the initial notes, from November 9, 2006. Initial notes that we accept for exchange will cease to accrue interest from and after the date of completion of the exchange offer. Under the registration rights agreement, we may be required to make additional interest payments to the holders of the initial notes under circumstances relating to the timing of the exchange offer.

In all cases, issuance of notes for initial notes will be made only after timely receipt by the exchange agent of:

• certificate for the initial notes, or a timely book-entry confirmation of the initial notes, into the exchange agent’s account at the book-entry transfer facility;

• a properly completed and duly executed letter of transmittal or an agent’s message; and

• all other required documents.

Unaccepted or non-exchanged initial notes will be returned without expense to the tendering holder of the initial notes. In the case of initial notes tendered by book-entry transfer in accordance with the book-entry procedures described above, the non-exchanged initial notes will be credited to an account maintained with DTC as promptly as practicable after the expiration or termination of the exchange offer. For each initial note accepted for exchange, the holder of the initial note will receive a new note having a principal amount equal to that of the surrendered initial note.

Interest Payments on the Notes

Registered holders of notes on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the date of issuance of the initial notes. Initial notes accepted for exchange will cease to accrue interest from and after the date of completion of the exchange offer and will be deemed to have waived their rights to receive the accrued interest on the initial notes.

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Withdrawal Rights

Tender of initial notes may be properly withdrawn at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.

For a withdrawal to be effective with respect to initial notes, the exchange agent must receive a written notice of withdrawal before the expiration time delivered by hand, overnight by courier or by mail, at the address indicated under “—Exchange Agent” or, in the case of eligible institutions, at the facsimile number, or a properly transmitted “Request Message” through DTC’s ATOP system. Any notice of withdrawal must:

• specify the name of the person, referred to as the depositor, having tendered the initial notes to be withdrawn;

• identify the initial notes to be withdrawn, including certificate numbers and principal amount of the initial notes;

• contain a statement that the holder is withdrawing its election to have the initial notes exchanged;

• other than a notice transmitted through DTC’s ATOP system, be signed by the holder in the same manner as the original signature on the letter of transmittal by which the initial notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer to have the trustee with respect to the initial notes register the transfer of the initial notes in the name of the person withdrawing the tender; and

• specify the name in which the initial notes are registered, if different from that of the depositor.

If certificates for initial notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of these certificates, the withdrawing holder must also submit the serial numbers of the particular certificates to be withdrawn and signed notice of withdrawal with signatures guaranteed by an eligible institution, unless this holder is an eligible institution. If initial notes have been tendered in accordance with the procedure for book-entry transfer described below, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn initial notes.

Any initial notes properly withdrawn will be deemed not to have been validly tendered for exchange. Notes will not be issued in exchange unless the initial notes so withdrawn are validly re-tendered.

Properly withdrawn initial notes may be re-tendered by following the procedures described under “—Procedures for Tendering” above at any time at or before the expiration time.

We will determine all questions as to the validity, form and eligibility, including time of receipt, of notices of withdrawal.

Conditions to the Exchange Offer

Notwithstanding any other provisions of the exchange offer, or any extension of the exchange offer, we will not be required to accept for exchange, or to exchange, any initial notes for any notes, and, as described below, may terminate an exchange offer, whether or not any initial notes have been accepted for exchange, or may waive any conditions to or amend the exchange offer, if any of the following conditions has occurred or exists:

• there shall occur a change in the current interpretation by the staff of the SEC which permits the notes issued pursuant to such exchange offer in exchange for initial notes to be offered for resale, resold and otherwise transferred by the holders (other than broker-dealers and any holder which is an affiliate) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that such notes are acquired in the ordinary course of such holders’ business and such holders have no arrangement or understanding with any person to participate in the distribution of the notes;

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• any action or proceeding shall have been instituted or threatened in any court or by or before any governmental agency or body seeking to enjoin, make illegal or delay completion of the exchange offer or otherwise relating to the exchange offer;

• any law, statute, rule or regulation shall have been adopted or enacted which, in our judgment, would reasonably be expected to impair our ability to proceed with such exchange offer;

• a banking moratorium shall have been declared by United States federal or New York State authorities;

• trading on the New York Stock Exchange or generally in the United States over-the-counter market shall have been suspended, or a limitation on prices for securities imposed, by order of the SEC or any other governmental authority;

• an attack on the United States, an outbreak or escalation of hostilities or acts of terrorism involving the United States, or any declaration by the United States of a national emergency or war shall have occurred;

• a stop order shall have been issued by the SEC or any state securities authority suspending the effectiveness of the registration statement of which this prospectus is a part or proceedings shall have been initiated or, to our knowledge, threatened for that purpose or any governmental approval has not been obtained, which approval we shall, in our sole discretion, deem necessary for the consummation of such exchange offer; or

• any change, or any development involving a prospective change, in our business or financial affairs has occurred which is or may be adverse to us or we shall have become aware of facts that have or may have an adverse impact on the value of the initial notes or the notes, which in our sole judgment in any case makes it inadvisable to proceed with such exchange offer and/or with such acceptance for exchange or with such exchange.

If we determine in our sole discretion that any of the foregoing events or conditions has occurred or exists, we may, subject to applicable law, terminate the exchange offer, whether or not any initial notes have been accepted for exchange, or may waive any such condition or otherwise amend the terms of such exchange offer in any respect. Please read “—Expiration, Extension and Amendment” above.

If any of the above events occur, we may:

• terminate the exchange offer and promptly return all tendered initial notes to tendering holders;

• complete and/or extend the exchange offer and, subject to your withdrawal rights, retain all tendered initial notes until the extended exchange offer expires;

• amend the terms of the exchange offer; or

• waive any unsatisfied condition and, subject to any requirement to extend the period of time during which the exchange offer is open, complete the exchange offer.

We may assert these conditions with respect to the exchange offer regardless of the circumstances giving rise to them. All conditions to the exchange offer, other than those dependent upon receipt of necessary government approvals, must be satisfied or waived by us before the expiration of the exchange offer. We may waive any condition in whole or in part at any time in our reasonable discretion. Our failure to exercise our rights under any of the above circumstances does not represent a waiver of these rights. Each right is an ongoing right that may be asserted at any time. Any determination by us concerning the conditions described above will be final and binding upon all parties.

If a waiver constitutes a material change to the exchange offer, we will promptly disclose the waiver by means of a prospectus supplement that we will distribute to the registered holders of the initial notes, and we will extend the exchange offer for a period of five to ten business days, as required by applicable law, depending upon

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the significance of the waiver and the manner of disclosure to the registered holders, if the exchange offer would otherwise expire during the five to ten business day period.

Resales of Notes

Based on interpretations by the staff of the SEC, as described in no-action letters issued to third parties that are not related to us, we believe that notes issued in the exchange offer in exchange for initial notes may be offered for resale, resold or otherwise transferred by holders of the notes without compliance with the registration and prospectus delivery provisions of the Securities Act, if:

• the notes are acquired in the ordinary course of the holder’s business;

• the holders have no arrangement or understanding with any person to participate in the distribution of the notes;

• the holders are not “affiliates” of ours within the meaning of Rule 405 under the Securities Act; and

• the holders are not a broker-dealer who purchased initial notes directly from us for resale pursuant to Rule 144A, Regulation S or any other available exemption under the Securities Act.

However, the SEC has not considered the exchange offer described in this prospectus in the context of a no-action letter. The staff of the SEC may not make a similar determination with respect to the exchange offer as in the other circumstances. Each holder who wishes to exchange initial notes for notes will be required to represent that it meets the requirements above.

Any holder who is an affiliate of ours or who intends to participate in the exchange offer for the purpose of distributing notes or any broker-dealer who purchased initial notes directly from us for resale pursuant to Rule 144A, Regulation S or any other available exemption under the Securities Act:

• cannot rely on the applicable interpretations of the staff of the SEC mentioned above;

• will not be permitted or entitled to tender the initial notes in the exchange offer; and

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Each broker-dealer that receives notes for its own account in exchange for initial notes must acknowledge that the initial notes were acquired by it as a result of market-making activities or other trading activities and agree that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. Please read “Plan of Distribution.” A broker-dealer may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resales of notes received in exchange for initial notes that the broker-dealer acquired as a result of market-making or other trading activities. Any holder that is a broker-dealer participating in the exchange offer must notify the exchange agent at the telephone number set forth in the enclosed letter of transmittal and must comply with the procedures for broker-dealers participating in the exchange offer. We have not entered into any arrangement or understanding with any person to distribute the notes to be received in the exchange offer.

In addition, to comply with state securities laws, the notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification, with which there has been compliance, is available. The offer and sale of the notes to “qualified institutional buyers,” and foreign investors as defined under Rule 144A and Regulation S of the Securities Act, respectively, are generally exempt from registration or qualification under the state securities laws. We currently do not intend to register or qualify the sale of notes in any state where an exemption from registration or qualification is required and not available.

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Exchange Agent

The Bank of New York has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal and any other required documents should be directed to the exchange agent at the address or facsimile number set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent addressed as follows:

THE BANK OF NEW YORK

By Facsimile for Eligible Institutions: (212) 298-1915 Attention: Mrs. Evangeline R. Gonzales By Mail/Overnight Delivery/Hand: The Bank of New York Corporate Trust Operations 101 Barclay Street—7 East New York, New York 10286 Attention: Mrs. Evangeline R. Gonzales Confirm By Telephone: (212) 815-3738

DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET FORTH ABOVE OR TRANSMISSION OF SUCH LETTER OF TRANSMITTAL VIA FACSIMILE OTHER THAN AS SET FORTH ABOVE DOES NOT CONSTITUTE A VALID DELIVERY OF THE LETTER OF TRANSMITTAL.

Fees and Expenses

The expenses of soliciting tenders pursuant to this exchange offer will be paid by us. We have agreed to pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection with the exchange offer. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus and related documents to the beneficial owners of initial notes, and in handling or tendering for their customers. We will not make any payment to brokers, dealers or others soliciting acceptances of the exchange offer.

Holders who tender their initial notes for exchange will not be obligated to pay any transfer taxes on the exchange. If, however, notes are to be delivered to, or are to be issued in the name of, any person other than the registered holder of the initial notes tendered, or if a transfer tax is imposed for any reason other than the exchange of initial notes in connection with the exchange offer, then the amount of any such transfer taxes (whether imposed on the registered holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchange of initial notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of initial notes under the exchange offer.

Consequences of Failure to Exchange Outstanding Securities

Holders who desire to tender their initial notes in exchange for notes registered under the Securities Act should allow sufficient time to ensure timely delivery. Neither the exchange agent nor us is under any duty to give notification of defects or irregularities with respect to the tenders of initial notes for exchange.

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Initial notes that are not tendered or are tendered but not accepted will, following the completion of the exchange offer, continue to be subject to the provisions in the indenture regarding the transfer and exchange of the initial notes and the existing restrictions on transfer set forth in the legend on the initial notes set forth in the indenture for the notes. Except in limited circumstances with respect to specific types of holders of initial notes, we will have no further obligation to provide for the registration under the Securities Act of such initial notes. In general, initial notes, unless registered under the Securities Act, may not be offered or sold except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws.

We do not currently anticipate that we will take any action to register the initial notes under the Securities Act or under any state securities laws. Upon completion of the exchange offer, holders of the initial notes will not be entitled to any further registration rights under the registration rights agreement, except under limited circumstances.

Accounting Treatment

We will record the notes at the same carrying value as the initial notes, as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes. The expenses of the exchange offer will be amortized over the term of the notes.

Other

Participation in the exchange offer is voluntary, and you should consider carefully whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

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DESCRIPTION OF NOTES

You can find the definitions of certain terms used in this description under the subheading “Certain Definitions.” In this description, the word “Sabine Pass LNG” refers only to Sabine Pass LNG, L.P. and not to any of its partners or potential future subsidiaries. References to the “notes” refer to the 2013 notes and the 2016 notes collectively.

We issued the initial notes under a secured notes indenture between us and The Bank of New York, as trustee (the “Trustee”). We refer to the secured notes indenture as the indenture. We will issue the notes under the same indenture under which we issued the initial notes, and the notes will represent the same debt as the initial notes for which they are exchanged.

The indenture is governed by the Trust Indenture Act of 1939, as amended. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act. The security documents referred to below under the caption “—Security” by and among Sabine Pass LNG and The Bank of New York, as collateral trustee (the “Collateral Trustee”), contain the terms of the security arrangements that will secure the notes.

The following description is a summary of the material provisions of the indenture and the security documents. It does not restate those agreements in their entirety. We urge you to read the indenture and the security documents because they, and not this description, define your rights as holders of the notes. Copies of the indenture and the security documents have been filed as exhibits to the registration statement of which this prospectus is a part. Certain defined terms used in this description but not defined below under “—Certain Definitions” have the meanings assigned to them in the indenture.

The registered holder of any note will be treated as the owner of it for all purposes. Only registered holders will have rights under the indenture.

Brief Description of Notes and the Note Guarantees

The Notes

The notes:

• will be general obligations of Sabine Pass LNG;

• will be secured on a first-priority basis subject only to the Assumption Agreement and Permitted Liens by security interests in all Shared Collateral owned or at any time acquired by Sabine Pass LNG;

• will bepari passu in right of payment with all existing and future Senior Debt (other than the Assumption Agreement) of Sabine Pass LNG;

• will be senior in right of payment to any future Subordinated Indebtedness of Sabine Pass LNG; and

• will be unconditionally guaranteed by the Guarantors, if applicable.

We have no indebtedness outstanding other than the initial notes.

The Note Guarantees

The notes will be guaranteed by all of Sabine Pass LNG’s future Domestic Subsidiaries, if any.

Each guarantee of the notes:

• will be a general obligation of the Guarantor;

• will be secured on a first-priority basis subject only to the Assumption Agreement and Permitted Liens by security interests in all Shared Collateral owned or at any time acquired by that Guarantor;

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• will bepari passu in right of payment with all existing and future Senior Debt of that Guarantor (other than the Assumption Agreement); and

• will be senior in right of payment to any future Subordinated Indebtedness of that Guarantor.

As of the date of the indenture Sabine Pass LNG has no subsidiaries. Under the circumstances described below under the caption “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries,” we will be permitted to designate certain of our Subsidiaries as “Unrestricted Subsidiaries.” Our Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. Our Unrestricted Subsidiaries will not guarantee the notes.

Principal, Maturity and Interest

Sabine Pass LNG has issued $550 million in aggregate principal amount of 2013 notes and $1,482 million in aggregate principal amount of 2016 notes. Sabine Pass LNG may issue additional notes under the indenture from time to time. Any issuance of additional notes is subject to all of the covenants in the indenture, including the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock.” The 2013 notes and any additional 2013 notes subsequently issued under the indenture will be treated as a single class and the 2016 notes and any additional 2016 notes issued under the indenture will be treated as a single class, in each case, for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. Sabine Pass LNG will issue notes in denominations of $100,000 and integral multiples of $1,000 in excess of $100,000. The 2013 notes will mature on November 30, 2013 and the 2016 notes will mature on November 30, 2016.

2013 Notes

Interest on the 2013 notes will accrue at the rate of 7 ¹/4% per annum and will be payable semi-annually in arrears on May 30 and November 30, commencing on May 30, 2007. Interest on overdue principal and interest and Additional Interest, if any, will accrue at a rate that is 1% higher than the then applicable interest rate on the 2013 notes. Sabine Pass LNG will make each interest payment to the holders of record on the immediately preceding May 15 and November 15.

Interest on the 2013 notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

2016 Notes

Interest on the 2016 notes will accrue at the rate of 7 ¹/2% per annum and will be payable semi-annually in arrears on May 30 and November 30, commencing on May 30, 2007. Interest on overdue principal and interest and Additional Interest, if any, will accrue at a rate that is 1% higher than the then applicable interest rate on the 2016 notes. Sabine Pass LNG will make each interest payment to the holders of record on the immediately preceding May 15 and November 15.

Interest on the 2016 notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Methods of Receiving Payments on the Notes

All payments on the notes will be made at the office or agency of the paying agent and registrar within the City and State of New York unless Sabine Pass LNG elects to make interest payments by check mailed to the noteholders at their address set forth in the register of holders.

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Paying Agent and Registrar for the Notes

The Trustee will initially act as paying agent and registrar. Sabine Pass LNG may change the paying agent or registrar without prior notice to the holders of the notes, and Sabine Pass LNG or any of its Subsidiaries may act as paying agent or registrar.

Transfer and Exchange

A holder may transfer or exchange notes in accordance with the provisions of the indenture. The registrar and the Trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders will be required to pay all taxes due on transfer. Sabine Pass LNG will not be required to transfer or exchange any note selected for redemption. Also, Sabine Pass LNG will not be required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed.

Funding of Interest Payments During Construction Period

As described in further detail below in “—Pre-Completion Account Flows—DSR Account,” on the Issue Date, amounts, together with interest on such amounts and $20.0 million that is expected to be earned on amounts in deposit in the Construction Account as described below, which is expected to be sufficient to fund five semi-annual interest payments on the notes were set aside in the DSR Account.

Note Guarantees

The 2013 notes and 2016 notes will be guaranteed by each of Sabine Pass LNG’s future Domestic Subsidiaries. These Note Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee will be limited as necessary to prevent that Note Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors—Federal and state statutes allow courts, under specific circumstances, to void guarantees and require note holders to return payments received from guarantors.”

A Guarantor may not sell or otherwise dispose of all or substantially all of its assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person) another Person, other than Sabine Pass LNG or another Guarantor, unless:

(1) immediately after giving effect to that transaction, no Default or Event of Default exists; and

(2) either:

(a) the Person acquiring the property in any such sale or disposition or the Person formed by or surviving any such consolidation or merger assumes all the obligations of that Guarantor under the indenture, its Note Guarantee and the registration rights agreement pursuant to a supplemental indenture and appropriate Security Documents satisfactory to the Trustee; or

(b) the Net Proceeds of such sale or other disposition are applied in accordance with the applicable provisions of the indenture.

The Note Guarantee of a Guarantor will be released:

(1) in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) Sabine Pass LNG or a Restricted Subsidiary of Sabine Pass LNG, if the sale or other disposition does not violate the “Asset Sale” provisions of the indenture;

(2) in connection with any sale or other disposition of all of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) Sabine Pass LNG or a Restricted Subsidiary of Sabine Pass LNG, if the sale or other disposition does not violate the “Asset Sale” provisions of the indenture;

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(3) if Sabine Pass LNG designates any Restricted Subsidiary that is a Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture; or

(4) upon legal defeasance or satisfaction and discharge of the indenture as provided below under the captions “—Legal Defeasance and Covenant Defeasance” and “—Satisfaction and Discharge.”

Project Accounts

Sabine Pass LNG will maintain a series of cash accounts (the “Project Accounts”) with the Collateral Trustee. The Project Accounts will be pledged to the Collateral Trustee for the benefit of the present and future holders of the Secured Obligations including notes. The following is a list of the Project Accounts through which the net proceeds of the notes and the revenues of the Project will flow:

Account	Currency	Location of Project Account
Construction Account	US$	New York
DSR Account	US$	New York
Revenue Account	US$	New York
Operating Account	US$	New York
Debt Payment Account	US$	New York

Pre-Completion Account Flows

Construction Account

Funds in the Construction Account will only be used (i) to fund the construction and start-up costs of the Project, (ii) to pay other expenses (including taxes, operating expenses and management fees) incidental for Sabine Pass LNG to complete the construction and commissioning of the Project, and (iii) to be transferred to other Project Accounts as described below. Sabine Pass LNG may make withdrawals from the Construction Account to fund construction costs or expenses of the Project then payable and estimated construction costs for the next forty-five (45) days as well as to fund the DSR Account from interest received on the Construction Account by issuing a withdrawal notice to the Trustee and Collateral Trustee no more frequently than once a month. The withdrawal notice will, among other things, specify the amount of the proposed withdrawal, the purpose of the proposed withdrawal, including details of the nature of the construction costs, that no Event of Default under the indenture has occurred and is continuing and that Sabine Pass LNG has sufficient funds (including amounts expected to be withdrawn from the Construction Account, binding equity commitments with respect to funds, anticipated insurance proceeds and/or available borrowings under Indebtedness permitted under the indenture) to achieve Phase 1 Target Completion. Pending disbursement, all funds contained in the Construction Account will be invested in cash or Cash Equivalents. Each month interest accrued on amounts in the Construction Account will be transferred to the DSR Account until an aggregate of $20.0 million of interest has been transferred to the DSR Account.

Revenue Account

All revenue received by Sabine Pass, other than the first $20 million, advance reservation or similar payments under terminal use or similar agreements in respect of the Project capacity, sales tax reimbursements and operating revenues from the Project shall be deposited in the Revenue Account. Amounts in the Revenue Account shall be applied to amounts owing in the following categories, if any, on the date of application of the funds:

Prior to Phase 1 Target Completion:

(i) first, to pay obligations under the Assumption Agreement;

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(ii) second, to the extent that amounts on deposit in the DSR Account are not sufficient to pay interest on the notes on the next interest payment date, to the DSR Account in an amount sufficient to make such payment and, at the option of Sabine Pass LNG, to deposit additional amounts in the DSR Account; and

(iii) third, to the Construction Account for application as provided in “Pre-Completion Account Flows—Construction Account” above.

DSR Account

The DSR Account was funded on the Issue Date with an amount that, together with interest to be earned on such account plus $20.0 million that is expected to be earned on amounts in the Construction Account, that is expected to be sufficient to pay the first five semi-annual interest payment on the notes. The Collateral Trustee will withdraw funds from the DSR Account on each interest payment date to pay the amount of interest then due and payable and to pay from time to time any amounts payable under the Assumption Agreement. Upon achievement of Phase 1 Final Completion and thereafter to the extent amounts are available as described in “—Post-Completion Account Flows—Revenue Account” below, Sabine Pass LNG will maintain an amount no less than the amount required to make the interest payment on the notes on the next succeeding interest payment date (the “Operating Period Required Amount”). Pending disbursement, all funds contained in the DSR Account will be invested in cash or Cash Equivalents. Amounts in the DSR Account are required to be maintained in U.S. dollars.

Post-Completion Account Flows

Construction Account

Upon Phase 1 Target Completion, any remaining funds in the Construction Account will be used, (i) first, to fund the Operating Account with an amount sufficient to cover any outstanding incurred construction expenses, operating expenses or maintenance capital expenditure and the next 45 days of the Project’s estimated operating expenses and maintenance capital expenditure; (ii) second, to pay any outstanding principal and interest on the notes then due and payable; and (iii) third, to fund any shortfall in the DSR Account such that the DSR Account contains the Operating Period Required Amount. After all funds have been applied as described in (i) through (iii) above, the remaining funds, if any, shall be transferred to the Revenue Account. Pending disbursement, all funds contained in the Construction Account will be invested in cash or Cash Equivalents.

Revenue Account

Following Phase 1 Target Completion, amounts in the Revenue Account shall be applied as follows:

(i) first, to fund the Operating Account with amounts sufficient to cover the succeeding 45 days of Operation and Maintenance Expenses, maintenance capital expenditures and obligations under the Assumption Agreement and, so long as the relevant state or local combined, consolidated or unitary tax return is properly filed that includes Sabine Pass LNG and Parent, State Tax Sharing Agreement;

(ii) second, 1/6th of the amount of interest due on the notes on the next interest payment date (plus any shortfall from any prior month subsequent to the preceding interest payment date) shall be transferred to the Debt Payment Account;

(iii) third, to pay outstanding principal then due and payable on the notes;

(iv) fourth, to pay taxes payable by Sabine Pass LNG or the Guarantors and payments in respect of taxes;

(v) fifth, to replenish the DSR Account when such account is not funded with the Operating Period Required Amount; provided that the Operating Period Required Amount shall be deemed reduced by the face amount of any Acceptable Letter of Credit or Acceptable Guarantees procured by Sabine Pass LNG for the benefit of the Collateral Trustee; and

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(vi) sixth, for all other purposes permitted by the indenture including Restricted Payments, subject to the limitations contained in the indenture.

Notwithstanding the foregoing, any Indebtedness issued to complete Phase 1 construction and/or Phase 2 construction shall be maintained in the Revenue Account to pay the construction costs for Phase 1 and/or Phase 2. Any such amounts Sabine Pass LNG determines not to use to fund Phase 1 or Phase 2 construction shall be used to make an offer to all holders of the notes and all holders of other Indebtedness that ispari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of funds not used to fund Phase 1 or Phase 2 construction, to purchase the maximum principal amount of notes and such otherpari passu Indebtedness that may be purchased out of such amounts not used to fund Phase 1 or Phase 2 construction. The offer price will be equal to 100% of the principal amount plus accrued and unpaid interest and Additional Interest, if any, to the date of purchase, and will be payable in cash. If any amounts remain unapplied after consummation of such offer, Sabine Pass LNG and its Restricted Subsidiaries may use such amounts for any purpose not otherwise prohibited by the indenture.

Debt Payment Account

On each interest payment date, amounts on deposit in the Debt Payment Account shall be transferred to the Trustee to be applied to pay interest on the notes.

Operating Account

The Operating Account will be funded in U.S. dollars in the amount in the aggregate to be expended during the immediately following 45 days by Sabine Pass LNG and the Guarantors for operating lease payments, other Operation and Maintenance Expense, maintenance capital expenditures for the Project and obligations under the Assumption Agreement and, so long as the relevant state or local combined, consolidated or unitary tax return is properly filed that includes Sabine Pass LNG and Parent, the State Tax Sharing Agreement.

DSR Account

Following the fifth interest payment date on the notes, to the extent amounts are available as described in “Post-Completion Account Flows—Revenue Account” above, the DSR Account shall be funded in an amount not less than the amount required to make the next interest payment on the notes on the next succeeding interest payment date for the notes. Amounts in excess of such interest payment shall be transferred to the Revenue Account. Pending disbursement, all funds contained in the DSR Account will be held as cash or invested in Cash Equivalents.

Amounts in the DSR Account will be maintained in US dollars.

Discretionary Capital Expenditures and Restricted Payments

Any remaining funds after application through the cash waterfall described above may be used by Sabine Pass LNG to fund discretionary capital expenditures for the Project or, if the conditions set forth below under “—Certain Covenants—Restricted Payments” have been satisfied in full, to fund cash dividends or cash distributions in accordance with the provisions of the indenture.

Security

The payment of the notes, when due, and the performance of all other Parity Secured Debt are secured equally and ratably by liens upon Sabine Pass LNG’s rights in the Shared Collateral. The payment of the guarantees of each Guarantor and all other obligations of such Guarantor, when due, and the performance of all

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other obligations of such Guarantor with respect to Parity Secured Debt under the Secured Debt Documents are secured equally and ratably by liens upon such Guarantor’s rights in the Shared Collateral.

Collateral Trust Agreement

On the date of the indenture, Sabine Pass LNG and the other Pledgors entered into a collateral trust agreement with the Collateral Trustee, which sets forth the terms on which the Collateral Trustee receives, holds, administers, maintains, enforces and distributes the proceeds of all Liens upon any Shared Collateral at any time delivered to it, in trust for the benefit of the present and future holders of the Secured Obligations, including the holders of the notes. The 2013 notes and the 2016 notes have been designated as Parity Secured Debt for purposes of the collateral trust agreement.

Collateral Trustee

Pursuant to the collateral trust agreement, Sabine Pass LNG has appointed the Collateral Trustee for the benefit of the holders of:

• the 2013 notes;

• the 2016 notes;

• any and all future Parity Secured Debt; and

• all other Secured Obligations outstanding from time to time including the Assumption Agreement. The lien priority and payment rights of the obligees under the Assumption Agreement shall be senior to the lien priority and payment rights of the holders of the notes.

The Collateral Trustee (directly or through co-trustees, agents or sub-agents) holds, and is entitled to enforce, all Liens on the Shared Collateral; provided that it shall be a condition precedent to any sale of the Shared Collateral that such purchaser enter into an assumption agreement substantially in the form of the Assumption Agreement unless, at the time of each such transfer, the Parent or any of its Affiliates, joint ventures, and subsidiaries that are involved in the LNG business have under contract at one or more LNG facilities it retains, the right and obligation to process and receive a tariff for processing at least 1.0 Bcf/d, for a period of at least five years following such transfer of assets.

Except as provided in the collateral trust agreement or the Security Documents or as directed by an Act of Required Debtholders, the Collateral Trustee is not obligated:

(1) to act upon directions purported to be delivered to it by any other Person;

(2) to foreclose upon or otherwise enforce any Lien; or

(3) to take any other action whatsoever with regard to any or all of the Security Documents, the Liens created thereby or the Shared Collateral.

Shared Collateral

The indenture and the Security Documents provide that:

(1) the notes will be secured, together with all other Parity Secured Debt of Sabine Pass LNG, equally and ratably by security interests granted to the Collateral Trustee in all of the assets of Sabine Pass LNG, and

(2) each Guarantor’s subsidiary guarantees will be secured, together with such Guarantor’s guarantee of all future Parity Secured Debt of such Guarantor, equally and ratably by security interests granted to the Collateral Trustee in all assets of such Guarantor.

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The Shared Collateral consists of substantially all of the operating assets of Sabine Pass LNG and the Guarantors, including:

(1) a pledge by Sabine Pass LNG-LP, LLC and Sabine Pass LNG-GP, Inc. of all ownership interests in Sabine Pass LNG;

(2) a collateral assignment of Sabine Pass LNG’ rights in the Material Project Agreements;

(3) a collateral assignment of Sabine Pass LNG’s rights in the Cheniere Marketing TUA;

(4) a mortgage on all real property, machinery and equipment;

(5) a security interest in all Project Accounts and Permitted Investments;

(6) a collateral assignment of all insurance policies;

(7) a collateral assignment of all intellectual property and Project related governmental approvals to the extent assignable;

(8) a collateral assignment of all receivables;

(9) a pledge of any intercompany debt; and

(10) a pledge of the Sabine Pass LNG’ interest, if any, in the inventory of natural gas or LNG stored on the Project’s premises.

Additional Parity Secured Debt

The indenture and the Security Documents provide that Sabine Pass LNG may incur additional Parity Secured Debt by issuing additional notes under the indenture. The additional Parity Secured Debt will bepari passu with the notes, will be guaranteed on apari passu basis by each Guarantor and will be secured by the Shared Collateral equally and ratably with the notes for as long as the notes and guarantees of notes, subject to the covenants contained in the indenture, are secured by the Shared Collateral. The additional Parity Secured Debt will only be permitted to share in the Shared Collateral if such Indebtedness and the related Liens are permitted to be incurred under the covenants described below under the captions “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” and “—Certain Covenants—Liens.”

Equal and Ratable Sharing of Shared Collateral by Holders of Parity Secured Debt

Notwithstanding (1) anything to the contrary contained in the Secured Debt Documents, (2) the time of incurrence of any Series of Parity Secured Debt, (3) the order or method of attachment or perfection of any Liens securing any Series of Parity Secured Debt, (4) the time or order of filing or recording of financing statements, mortgages or other documents filed or recorded to perfect any Lien upon any Shared Collateral, (5) the time of taking possession or control over any Shared Collateral or (6) the rules for determining priority under any law governing relative priorities of Liens:

(A) all Liens at any time granted by the General Partner, the Limited Partner, Sabine Pass LNG or any of its subsidiaries in the Shared Collateral to secure any of the Parity Secured Debt shall secure, equally and ratably, all liabilities of the General Partner, the Limited Partner, Sabine Pass LNG or such subsidiary under or in respect of the Parity Secured Debt; and

(B) after paying or discharging obligations if any outstanding under the Assumption Agreement, all proceeds of all Liens at any time granted by the General Partner, the Limited Partner, Sabine Pass LNG or any of its subsidiaries in the Shared Collateral to secure any of the Parity Secured Debt shall be allocated and distributed equally and ratably on account of all liabilities of the General Partner, the Limited Partner, Sabine Pass LNG or such subsidiary under or in respect of the Parity Secured Debt.

The foregoing provision is intended for the benefit of, and will be enforceable as a third party beneficiary by, each present and future holder of Parity Secured Debt and each present and future Secured Debt Representative.

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Enforcement of Security Interests

If the Collateral Trustee at any time receives written notice that any event has occurred that constitutes a default under any Secured Debt Document entitling the Collateral Trustee to foreclose upon, collect or otherwise enforce its Liens thereunder, it will promptly deliver written notice thereof to each Secured Debt Representative. Thereafter, the Collateral Trustee may await direction by an Act of Required Debtholders and will act, or decline to act, as directed by an Act of Required Debtholders, in the exercise and enforcement of the Collateral Trustee’s interests, rights, powers and remedies in respect of the Shared Collateral or under the Security Documents or applicable law and, following the initiation of such exercise of remedies, the Collateral Trustee will act, or decline to act, with respect to the manner of such exercise of remedies as directed by an Act of Required Debtholders. Unless it has been directed to the contrary by an Act of Required Debtholders, the Collateral Trustee in any event may (but will not be obligated to) take or refrain from taking such action with respect to any default under any Secured Debt Document as it may deem advisable and in the best interest of the holders of Secured Obligations.

Junior Liens

The indenture also permits Sabine Pass LNG and the Guarantors to grant Liens on all or portions of the Shared Collateral that are subordinated to the Liens securing the Secured Obligations. See “Certain Covenants—Liens.” These Liens will be subject to subordination terms set forth in the collateral trust agreement, including an agreement by the holders of such Liens not to exercise any remedies with respect to the Shared Collateral until the Secured Debt Termination Date. The holders of such Liens will also not be entitled to the proceeds of any Shared Collateral upon a sale thereof until the Secured Debt Termination Date.

Order of Application

The collateral trust agreement provides that if, pursuant to the exercise of any default remedies set forth in any security document, any Shared Collateral is sold or otherwise realized upon by the Collateral Trustee, the proceeds received by the Collateral Trustee in respect of such Shared Collateral will be distributed by the Collateral Trustee in the following order of application (the “Order of Application”):

FIRST, paid to the payment of any amounts due by Sabine Pass LNG under the Assumption Agreement;

SECOND, to the payment of all reasonable legal fees and expenses and other reasonable costs or expenses or other liabilities of any kind incurred by the Collateral Trustee or any co-trustee or agent in connection with any security document, including the reimbursement to any Secured Debt Representative of any amounts theretofore advanced by such Secured Debt Representative for the payment of such fees, costs and expenses;

THIRD, to the Collateral Trustee (without duplication) in an amount equal to the Collateral Trustee’s fees which are unpaid and to any Secured Debt Representative which has theretofore advanced or paid any such Collateral Trustee’s fees in an amount equal to the amount thereof so advanced or paid by such Secured Debt Representative;

FOURTH, to the respective Secured Debt Representatives for application to the Parity Secured Debt equally and ratably until all Parity Secured Debt has been paid in full in cash for distribution, to (1) in the case of note Obligations, to the Trustee for application pursuant to the indenture and (2) in the case of all other Parity Secured Debt, to the respective Secured Debt Representatives for application pursuant to the applicable Secured Debt Documents; and

FIFTH, any surplus remaining after the payment in full in cash of all of the Secured Obligations shall be paid to the applicable Pledgor, its successors or assigns, or to whomsoever may be lawfully entitled to receive the same, or as a court of competent jurisdiction may direct.

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Release of Security Interests

The indenture and the collateral trust agreement provide that the Collateral Trustee’s Liens upon the Shared Collateral will be released:

(1) in whole, at any time, if neither Sabine Pass LNG nor any Guarantor has any Secured Debt nor Junior Lien Debt secured by Liens under the Security Documents;

(2) as to any or all Shared Collateral at any time, if (A) consent to the release of Shared Collateral has been given by an Act of Required Debtholders and (B) such release has become effective in accordance with the terms of such consent;

(3) as to (A) deposits in any cash collateral account that are to be applied to fund any mandatory prepayment or purpose offer (including an Asset Sale Offer) that becomes required as to any Secured Debt as a result of a sale of assets, concurrently with such application, so long as effective provision is made for apportionment of such funding to all holders of Secured Debt entitled to participate in such mandatory prepayment or purchase offer in accordance with their respective entitlements under the Secured Debt Documents; and (B) deposits in any cash collateral account that constitute proceeds from an asset sale that are permitted under the Secured Debt Documents to be reinvested or otherwise are not required under the Secured Debt Documents to be reinvested or otherwise are not required to be applied to a mandatory prepayment or purchase offer in respect of any Secured Debt, concurrently with such reinvestment in assets constituting Shared Collateral or other permitted use under the Secured Debt Documents;

(4) in accordance with the provisions of the Security Documents as in effect from time to time; or

(5) in order to permit the consummation of any Asset Sales permitted by the indenture.

With respect to the notes or each series of notes, the indenture also will provide that the Collateral Trustee’s Liens upon Shared Collateral will no longer secure the note Obligations with respect to the notes or that series of notes and the right of the holders of such note Obligations to the benefits and proceeds of the Collateral Trustee’s Liens on Shared Collateral will terminate and be discharged:

(1) upon satisfaction and discharge of the indenture as set forth under the caption “—Satisfaction and Discharge”;

(2) upon a Legal Defeasance or Covenant Defeasance with respect to that series of notes as set forth under the caption “—Legal Defeasance and Covenant Defeasance”; or

(3) upon payment in full in cash of the applicable notes and all other related note Obligations that are outstanding, due and payable at the time the notes are paid in full in cash.

Sabine Pass LNG will otherwise comply with the provisions of TIA §314(b).

To the extent applicable, Sabine Pass LNG will cause TIA §313(b), relating to reports, and TIA §314(d), relating to the release of property or securities or relating to the substitution therefor of any property or securities to be subjected to the Lien of the Security Documents, to be complied with. Any certificate or opinion required by TIA §314(d) may be made by an officer of Sabine Pass LNG except in cases where TIA §314(d) requires that such certificate or opinion be made by an independent Person, which Person will be an independent engineer, appraiser or other expert selected or reasonably satisfactory to the Trustee. Notwithstanding anything to the contrary in this paragraph, Sabine Pass LNG will not be required to comply with all or any portion of TIA §314(d) (1) with respect to certain ordinary course of business releases of Shared Collateral as described in the indenture and (2) if it determines, in good faith based on advice of counsel, that under the terms of TIA §314(d) and/or any interpretation or guidance as to the meaning thereof of the Commission and its staff, including “no action” letters or exemptive orders, all or any portion of TIA §314(d) is inapplicable to one or a series of released Shared Collateral.

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To the extent applicable, Sabine Pass LNG will furnish to the Trustee, prior to each proposed release of Shared Collateral pursuant to the Security Documents:

(1) all documents required by TIA §314(d); and

(2) an opinion of counsel to the effect that such accompanying documents constitute all documents required by TIA §314(d).

Optional Redemption

2013 Notes

At any time prior to November 30, 2009, Sabine Pass LNG may redeem up to 35% of the aggregate original principal amount of the 2013 notes issued under the indenture at a redemption price of 107.25% of the principal amount, plus accrued and unpaid interest and Additional Interest, if any, to the redemption date, with the net cash proceeds of one or more Equity Offerings; provided that:

(1) at least 65% of the aggregate principal amount of the 2013 notes originally issued on the Issue Date (excluding notes held by Sabine Pass LNG and its Affiliates) remains outstanding immediately after the occurrence of such redemption; and

(2) the redemption occurs within 90 days of the date of the closing of such Equity Offering.

Sabine Pass LNG may also redeem all or a part of the notes, upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to each holder’s registered address, at a redemption price equal to 100% of the principal amount of notes redeemed plus the Applicable Premium, and accrued and unpaid interest and Additional Interest, if any, to the date of redemption (the “Redemption Date”), subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

2016 Notes

At any time prior to November 30, 2009, Sabine Pass LNG may redeem up to 35% of the aggregate original principal amount of the 2016 notes issued under the indenture at a redemption price of 107.50% of the principal amount, plus accrued and unpaid interest and Additional Interest, if any, to the redemption date, with the net cash proceeds of one or more Equity Offerings; provided that:

(1) at least 65% of the aggregate principal amount of the 2016 notes originally issued on the Issue Date (excluding notes held by Sabine Pass LNG and its Affiliates) remains outstanding immediately after the occurrence of such redemption; and

(2) the redemption occurs within 90 days of the date of the closing of such Equity Offering.

Sabine Pass LNG may also redeem all or a part of the notes, upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to each holder’s registered address, at a redemption price equal to 100% of the principal amount of notes redeemed plus the Applicable Premium, and accrued and unpaid interest and Additional Interest, if any, to the Redemption Date, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

Selection and Notice

If less than all of the notes are to be redeemed at any time, the Trustee will select notes for redemption on a pro rata basis unless otherwise required by law or applicable stock exchange requirements.

No notes of $100,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at

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its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture. Notices of redemption may not be conditional.

If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the holder of notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of notes called for redemption.

Open Market Purchases; No Mandatory Redemption or Sinking Fund

Sabine Pass LNG may at any time and from time to time purchase notes in the open market or otherwise. Sabine Pass LNG is not required to make mandatory redemption or sinking fund payments with respect to the notes.

Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, each holder of notes will have the right to require Sabine Pass LNG to repurchase all or any part (equal to $100,000 and integral multiples of $1,000 in excess thereof) of that holder’s notes pursuant to an offer (a “Change of Control Offer”) on the terms set forth in the indenture. In the Change of Control Offer, Sabine Pass LNG will offer payment (a “Change of Control Payment”) in cash equal to not less than 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest and Additional Interest, if any, to the date of repurchase (the “Change of Control Payment Date,” which date will be no earlier than the date of such Change of Control). No later than 30 days following any Change of Control, Sabine Pass LNG will mail a notice to each holder describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes on the Change of Control Payment Date specified in such notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the indenture and described in such notice. Sabine Pass LNG will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the indenture, or compliance with the Change of Control provisions of the indenture would constitute a violation of any such laws or regulations, Sabine Pass LNG will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such compliance.

On the Change of Control Payment Date, Sabine Pass LNG will, to the extent lawful:

(1) accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;

(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

(3) deliver or cause to be delivered to the Trustee the notes properly accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions of notes being purchased by Sabine Pass LNG.

The paying agent will promptly mail to each holder of notes properly tendered the Change of Control Payment for such notes, and the Trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered,

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if any; provided that each such new note will be in a principal amount of $100,000 or an integral multiple of $1,000 in excess thereof.

Sabine Pass LNG will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

If holders of not less than 95% in aggregate principal amount of the outstanding notes validly tender and do not withdraw such notes in a Change of Control Offer and Sabine Pass LNG, or any third party making a Change of Control Offer in lieu of Sabine Pass LNG as described above, purchases all of the notes validly tendered and not withdrawn by such holders, Sabine Pass LNG will have the right, upon not less than 30 nor more than 60 days’ prior notice, given not more than 30 days following such purchase pursuant to the Change of Control Offer described above, to redeem all notes that remain outstanding following such purchase at a redemption price in cash equal to the applicable Change of Control Payment plus, to the extent not included in the Change of Control Payment, accrued and unpaid interest, if any, and Additional Interest, if any thereon, to the date of redemption.

The provisions described above that require Sabine Pass LNG to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the holders of the notes to require that Sabine Pass LNG repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

Sabine Pass LNG will not be required to make a Change of Control Offer upon a Change of Control if (1) a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by Sabine Pass LNG and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, or (2) notice of redemption has been given pursuant to the indenture as described above under the caption “—Optional Redemption,” unless and until there is a default in payment of the applicable redemption price.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, transfer, conveyance or other disposition of “all or substantially all” of our properties or assets and its Restricted Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require us to repurchase such notes as a result of a sale, transfer, conveyance or other disposition of less than all of our assets and our Restricted Subsidiaries taken as a whole to another Person or group may be uncertain.

Asset Sales

Sabine Pass LNG will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1) Sabine Pass LNG (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale equal to the greater of (i) the Fair Market Value of the assets or Equity Interests issued or sold or otherwise disposed of and (ii) an amount equal to the invested cost of the assets sold or otherwise disposed of, less depreciation; and

(2) at least 90% of the consideration therefor received by Sabine Pass LNG or such Restricted Subsidiary is in the form of cash, Cash Equivalents or Replacement Assets or a combination thereof. For purposes of this provision, each of the following will be deemed to be cash:

(a) any liabilities, as shown on Sabine Pass LNG’s or such Restricted Subsidiary’s most recent consolidated balance sheet (or as would be shown on Sabine Pass LNG’s consolidated balance

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sheet as of the date of such Asset Sale) of Sabine Pass LNG or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Note Guarantee) that are assumed by the transferee of any such assets pursuant to a written novation agreement that releases Sabine Pass LNG or such Restricted Subsidiary from further liability therefor; and

(b) any securities, notes or other obligations received by Sabine Pass LNG or any such Restricted Subsidiary from such transferee that are converted by Sabine Pass LNG or such Restricted Subsidiary into cash within 90 days after such Asset Sale, to the extent of the cash received in that conversion.

Within 360 days after the receipt of any Net Proceeds from an Asset Sale, Sabine Pass LNG (or the applicable Restricted Subsidiary, as the case may be) may apply an amount equal to such Net Proceeds:

(1) to repay Senior Debt; or

(2) to make any capital expenditure or to purchase Replacement Assets (or enter into a binding agreement to make such capital expenditure or to purchase such Replacement Assets; provided that (a) such capital expenditure or purchase is consummated within the later of (x) 360 days after the receipt of the Net Proceeds from the related Asset Sale and (y) 180 days after the date of such binding agreement and (b) if such capital expenditure or purchase is not consummated within the period set forth in subclause (a), the amount not so applied will be deemed to be Excess Proceeds (as defined below)).

Pending the final application of any Net Proceeds, Sabine Pass LNG may reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture.

An amount equal to any Net Proceeds from Asset Sales that are not applied or invested as provided in the preceding paragraphs will constitute “Excess Proceeds.” If on any date, the aggregate amount of Excess Proceeds exceeds $25.0 million, then within ten Business Days after such date, Sabine Pass LNG will make an offer (an “Asset Sale Offer”) to all holders of notes and all holders of other Indebtedness that ispari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of sales of assets, to purchase the maximum principal amount of notes and such otherpari passu Indebtedness that may be purchased out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of principal amount plus accrued and unpaid interest and Additional Interest, if any, to the date of purchase, and will be payable in cash. If any Excess Proceeds remain unapplied after consummation of an Asset Sale Offer, Sabine Pass LNG and its Restricted Subsidiaries may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and otherpari passu Indebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the Trustee will select the notes and such otherpari passu Indebtedness to be purchased on a pro rata basis. Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

Notwithstanding the foregoing, the sale, conveyance or other disposition of all or substantially all of the assets of Sabine Pass LNG and its Restricted Subsidiaries, taken as a whole, will be governed by the provisions of the indenture described under the caption “—Repurchase at the Option of Holders—Change of Control” and/or the provisions described under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant.

Sabine Pass LNG will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sales provisions of the indenture, or compliance with the Asset Sale provisions of the indenture would constitute a violation of any such laws or regulations, Sabine Pass LNG will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indenture by virtue of such compliance.

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The future agreements governing Sabine Pass LNG’s other Indebtedness may contain prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale and including repurchases of or other prepayments in respect of the notes. The exercise by the holders of notes of their right to require Sabine Pass LNG to repurchase the notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchases on Sabine Pass LNG. In the event a Change of Control or Asset Sale occurs at a time when Sabine Pass LNG is prohibited from purchasing notes, Sabine Pass LNG could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If Sabine Pass LNG does not obtain a consent or repay those borrowings, Sabine Pass LNG will remain prohibited from purchasing notes. In that case, Sabine Pass LNG’s failure to purchase tendered notes would constitute an Event of Default under the indenture which could, in turn, constitute a default under the other Indebtedness. Finally, Sabine Pass LNG’s ability to pay cash to the holders of notes upon a repurchase may be limited by Sabine Pass LNG’s then existing financial resources. See “Risk Factors—We may not have the ability to raise the funds necessary to finance the change of control offer required by the indenture.”

Events of Loss

After any Event of Loss, Sabine Pass LNG may apply the Net Loss Proceeds from the Event of Loss to the rebuilding, repair, replacement or construction of improvements to the Project, with no obligation to make any purchase of any notes, provided, that with respect to any Event of Loss that results in Net Loss Proceeds equal to or greater than $100.0 million:

(1) Sabine Pass LNG delivers to the Trustee within 120 days of such Event of Loss a written opinion from a reputable contractor that the Project can be rebuilt, repaired, replaced or constructed and operating within 540 days following such Event of Loss; and

(2) Sabine Pass LNG delivers to the Collateral Trustee within 120 days of such Event of Loss a certificate from an Authorized Officer certifying that the applicable entity has available from Net Loss Proceeds, cash on hand, binding equity commitments with respect to funds, anticipated insurance proceeds and/or available borrowings under Indebtedness permitted under the indenture to complete the rebuilding, repair, replacement or construction described in clause (1) above and to pay debt service on its Indebtedness during the repair or restoration period.

Any Net Loss Proceeds that are not reinvested (or committed for reinvestment by Sabine Pass LNG) within 540 days following an Event of Loss will be deemed “Excess Loss Proceeds.” Within 15 days following the date on which the aggregate amount of Excess Loss Proceeds exceeds $100.0 million, Sabine Pass LNG will make an offer (an “Excess Loss Offer”) to all holders of notes to purchase the maximum principal amount of notes that may be purchased out of the Excess Loss Proceeds. The offer price in any Excess Loss Offer will be equal to 100% of principal amount plus accrued and unpaid interest to, but excluding, the date of purchase, and will be payable in cash. If any Excess Loss Proceeds remain after consummation of an Excess Loss Offer, Sabine Pass LNG may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes tendered into such Excess Loss Offer exceeds the amount of Excess Loss Proceeds, the Trustee will select the notes to be purchased on a pro rata basis. Upon completion of each Excess Loss Offer, the amount of Excess Loss Proceeds will be reset at zero.

If any payment date in connection with an Excess Loss Offer is on or after an interest record date but on or prior to the related interest payment date, then any accrued and unpaid interest shall be paid to the Person in whose name such note was registered at the close of business on such record date.

Sabine Pass LNG will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Excess Loss Offer. To the extent that the provisions of any securities laws or regulations conflict with the Excess Loss provisions of the indenture, Sabine Pass LNG will

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comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Excess Loss provisions of the indenture by virtue of such conflict.

Pending their application, all Net Loss Proceeds will be invested in Cash Equivalents held in an account in which the Collateral Trustee has a perfected security interest for the benefit of the holders of Secured Obligations, subject only to Permitted Liens. Sabine Pass LNG may withdraw funds from the collateral account upon delivery of a certificate of the Authorized Officers that such funds will be used to pay for or reimburse that entity for either (1) the actual cost of a permitted use of Net Loss Proceeds as provided above or (2) the Event of Loss Offer, in each case pursuant to the terms of the Security Documents. Sabine Pass LNG shall grant to the Collateral Trustee, on behalf of the holders, a security interest, subject only to Permitted Liens, on any property or assets rebuilt, repaired, replaced or constructed with such Net Loss Proceeds on the terms set forth in the indenture and the Security Documents.

In the event of an Event of Loss pursuant to clause (3) of the definition of “Event of Loss” with respect to property or assets that have a Fair Market Value (or replacement cost, if greater) in excess of $5.0 million, Sabine Pass LNG will be required to receive consideration at least 90% of which is in the form of cash or Cash Equivalents.

Certain Covenants

Restricted Payments

Sabine Pass LNG will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1) declare or pay any dividend or make any other payment or distribution on account of Sabine Pass LNG’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving Sabine Pass LNG or any of its Restricted Subsidiaries) or to the direct or indirect holders of Sabine Pass LNG’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of Sabine Pass LNG) and other than dividends or distributions payable to Sabine Pass LNG or a Restricted Subsidiary of Sabine Pass LNG;

(2) purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving Sabine Pass LNG) any Equity Interests of Sabine Pass LNG or any direct or indirect Parent of Sabine Pass LNG;

(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Subordinated Indebtedness (excluding any intercompany Indebtedness between or among Sabine Pass LNG and any of its Restricted Subsidiaries), except (a) a payment of interest or principal at the Stated Maturity thereof or (b) the purchase, repurchase or other acquisition of any such Indebtedness in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of such purchase, repurchase or other acquisition; or

(4) make any Restricted Investment

(all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as “Restricted Payments”),

unless, at the time of and after giving effect to such Restricted Payment:

(1) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment; and

(2) Sabine Pass LNG has successfully achieved Phase 1 Target Completion; and

(3) Sabine Pass LNG would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter

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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 Fixed Charge Coverage Ratio test described below under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock” (for the avoidance of doubt, the Restricted Payment itself will not be considered in such pro forma calculation); and

(4) the Debt Payment Account has on deposit the Required Debt Payment Amount; and

(5) the DSR Account has on deposit the Operating Period Required Amount.

So long as no Default has occurred and is continuing or would be caused thereby, the preceding provisions will not prohibit:

(1) the payment of any dividend or the consummation of any irrevocable redemption within 60 days after the date of declaration of the dividend or giving of the redemption notice, as the case may be, if at the date of declaration or notice, the dividend or redemption payment complied with the provisions of the indenture;

(2) the making of any Restricted Payment in exchange for, or out of the net cash proceeds of (i) the substantially concurrent sale (other than to a Subsidiary of Sabine Pass LNG) of, Equity Interests of Sabine Pass LNG (other than Disqualified Stock) or (ii) from the substantially concurrent contribution (other than by a Subsidiary of Sabine Pass LNG) of capital to Sabine Pass LNG in respect of its Equity Interests (other than Disqualified Stock); provided, that 50% of the net cash proceeds pursuant to clause (i) above that are not retained or expended by Sabine Pass LNG shall be used to make an offer to the holders of the notes and to the holder of other Parity Secured Debt, to purchase the maximum principal amount of notes and such other Parity Secured Debt that may be purchased with such 50% of the net cash proceeds. The offer price for the notes and the Parity Secured Debt will be equal to 100% of principal amount plus accrued and unpaid interest and Additional Interest, if any, to the date of purchase, and will be payable in cash. If any such net cash proceeds remain unapplied after consummation of the offer, Sabine Pass LNG and its Restricted Subsidiaries may use those proceeds for any purpose not otherwise prohibited by the indenture;

(3) the repurchase, redemption, defeasance or other acquisition or retirement for value of Subordinated Indebtedness (including the payment of any required premium and any fees and expenses incurred in connection with such repurchase, redemption, defeasance or other acquisition) with the net cash proceeds from a substantially concurrent incurrence of Permitted Refinancing Indebtedness so long as such Permitted Refinancing Indebtedness has a final scheduled maturity date equal or later than the earlier of (x) the final scheduled maturity date of the Subordinated Indebtedness being so redeemed, repurchased, acquired or retired or (y) 360 days following the maturity date of the notes;

(4) the payment of any dividend (or, in the case of any partnership or limited liability company, any similar distribution) by a Restricted Subsidiary of Sabine Pass LNG to the holders of the Equity Interests (other than Disqualified Stock) of such Restricted Subsidiary; provided that such dividend or similar distribution is paid to all holders of such Equity Interests on a pro rata basis based upon their respective holdings of such Equity Interests;

(5) the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of Sabine Pass LNG or any Restricted Subsidiary of Sabine Pass LNG held by any of Parent’s or Sabine Pass LNG’s (or any of its Restricted Subsidiaries’) current or former directors or employees; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $1.0 million in any twelve-month period (with unused amounts in any 12-month period being permitted to be carried over into succeeding 12-month periods; subject to a maximum payment of $2.5 million in any twelve-month period); provided,further, that the amounts in any 12-month period may be increased by an amount not to exceed the cash proceeds received by Sabine Pass LNG or any of its Restricted Subsidiaries from the sale of Sabine Pass LNG’s Equity Interests (other than

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Disqualified Stock) or Parent’s Equity Interests to any such directors or employees that occurs after the Issue Date;

(6) the repurchase, redemption or other acquisition or retirement of Equity Interests deemed to occur upon the exercise or exchange of stock options, warrants or other similar rights to the extent such Equity Interests represent a portion of the exercise or exchange price of those stock options, and the repurchase, redemption or other acquisition or retirement of Equity Interests made in lieu of withholding taxes resulting from the exercise or exchange of stock options, warrants or other similar rights;

(7) payments to fund the purchase by Sabine Pass LNG of fractional shares arising out of stock dividends, splits or combination or business combinations;

(8) the declaration and payment of regularly scheduled or accrued dividends to holders of any class or series of Disqualified Stock of Sabine Pass LNG or any Restricted Subsidiary of Sabine Pass LNG issued on or after the date of the indenture in accordance with the Fixed Charge Coverage Ratio test described below under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock”;

(9) the repayment of the Holdings Credit Agreement in an amount not to exceed $437.0 million, and the payment of any make-whole, break funding, early termination or other prepayment penalties or amounts in connection with such prepayment and the termination of any related Interest Rate Agreement with a portion of the net proceeds received by Sabine Pass LNG from the sale of the initial notes on the Issue Date;

(10) Permitted Payments to Parent; and

(11) payments for fees and costs pursuant to the Management Services Agreement, payments to the Operator pursuant to the O&M Agreement, so long as the relevant state or local combined, consolidated or unitary tax return is properly filed that includes Sabine Pass LNG and Parent, payments under the State Tax Sharing Agreement and, without duplication, payments under Section 6.6 of the Partnership Agreement.

Notwithstanding any provision or implication to the contrary, any revenues received by Sabine Pass LNG or a Restricted Subsidiary prior to Phase 1 Target Completion may be distributed upon Sabine Pass LNG fulfilling the conditions set forth above.

The amount of all Restricted Payments (other than cash) will be the Fair Market Value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by Sabine Pass LNG or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The Fair Market Value of any cash Restricted Payment shall be its face amount, and the Fair Market Value of any non-cash Restricted Payment exceeding $15.0 million shall be determined conclusively by two senior officers of Sabine Pass LNG acting in good faith whose conclusions with respect thereto shall be set forth in an officers’ certificate delivered to the Trustee, provided,however, that if the Fair Market Value of any non-cash Restricted Payment exceeds $25.0 million, such Fair Market Value shall be determined conclusively by the Board of Directors of the General Partner and set forth in a board resolution, and a certified copy of such board resolution shall be delivered to the Trustee. For purposes of determining compliance with this covenant, in the event that a Restricted Payment meets the criteria of more than one of the exceptions described in (1) through (11) above or is entitled to be made pursuant to the first paragraph of this covenant, Sabine Pass LNG shall, in its sole discretion, classify such Restricted Payment, or later classify, reclassify or re-divide all or a portion of such Restricted Payment, in any manner that complies with this covenant.

Incurrence of Indebtedness and Issuance of Preferred Stock

Sabine Pass LNG will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or

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otherwise, with respect to (collectively, “incur,” with “incurrence” having a correlative meaning) any Indebtedness (including Acquired Debt), and Sabine Pass LNG will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any shares of preferred stock; provided,however, that Sabine Pass LNG may incur Indebtedness (including Acquired Debt) and issue Disqualified Stock, and Restricted Subsidiaries may incur Indebtedness (including Acquired Debt) and issue preferred stock, if additional equity investments in Sabine Pass LNG are made (other than to redeem or repurchase outstanding Indebtedness), in which case Sabine Pass LNG and any of its Restricted Subsidiaries may incur $1.00 of additional Indebtedness for each $1.00 so contributed and Sabine Pass LNG has received written confirmation from each Credit Rating Agency that no Ratings Decline will occur as a result of the incurrence of such additional Indebtedness.

Notwithstanding the foregoing, the first paragraph of this covenant will not prohibit the incurrence of any of the following (the items of Indebtedness described below in this paragraph being referred to collectively as “Permitted Debt”):

(1) the incurrence by Sabine Pass LNG and the Guarantors of Indebtedness represented by the notes and the related Note Guarantees to be issued on the date of the indenture and the exchange notes and the related Note Guarantees to be issued pursuant to the registration rights agreement;

(2) the incurrence by Sabine Pass LNG or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge any Indebtedness (other than intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph of this covenant or clauses (1), (2) and (14) of this paragraph;

(3) the issuance by any of Sabine Pass LNG’s Restricted Subsidiaries to Sabine Pass LNG or to any of its Restricted Subsidiaries of shares of preferred stock; provided,however, that:

(a) any subsequent issuance or transfer of Equity Interests that results in any such preferred stock being held by a Person other than Sabine Pass LNG or a Restricted Subsidiary of Sabine Pass LNG; and

(b) any sale or other transfer of any such preferred stock to a Person that is not either Sabine Pass LNG or a Restricted Subsidiary of Sabine Pass LNG,

will be deemed, in each case, to constitute an issuance of such preferred stock by such Restricted Subsidiary that was not permitted by this clause (3);

(4) the incurrence, assumption or creation of obligations of Sabine Pass LNG or a Restricted Subsidiary pursuant to the Assumption Agreement;

(5) the incurrence, assumption or creation of obligations of Sabine Pass LNG or a Restricted Subsidiary pursuant to Interest Rate and Currency Hedges;

(6) the incurrence of a Guarantee by Sabine Pass LNG or any of its Restricted Subsidiaries of Indebtedness of Sabine Pass LNG or a Restricted Subsidiary of Sabine Pass LNG that was permitted to be incurred by another provision of this covenant; provided that if the Indebtedness being guaranteed is Subordinated Indebtedness, then the Guarantee shall be subordinated to the same extent as the contractual subordination applicable to the Indebtedness guaranteed;

(7) the incurrence by Sabine Pass LNG of Indebtedness in an amount not to exceed $100.0 million in respect of (i) cost overruns of the construction, cool down, commissioning and completion of Phase 1 and Phase 2 and (ii) to finance the restoration of the Project following an Event of Loss;

(8) the incurrence by Sabine Pass LNG of Indebtedness in respect of working capital in an amount not to exceed $20.0 million (subject to a temporary increase, in an amount not to exceed $75.0 million, such increase to terminate not later than December 31, 2010, to fund the purchase of LNG for cool down of the Project and the entering into by Sabine Pass LNG of any commodity hedging arrangements relating to such LNG);

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(9) the incurrence by Sabine Pass LNG or any of its Restricted Subsidiaries of Indebtedness in respect of workers’ compensation claims, self-insurance obligations, bankers’ acceptances, performance bonds, completion bonds, bid bonds, appeal bonds and surety bonds or other similar bonds or obligations, and any Guarantees or letters of credit functioning as or supporting any of the foregoing;

(10) Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business; provided that such Indebtedness is extinguished within five Business Days of its Incurrence;

(11) the incurrence by Sabine Pass LNG of Indebtedness to the extent that the net proceeds thereof are promptly deposited to defease or to satisfy and discharge the notes;

(12) Indebtedness consisting of the financing of insurance premiums in customary amounts consistent with the operations and business of Sabine Pass LNG and its Restricted Subsidiaries in the ordinary course of business;

(13) Subordinated Indebtedness between or among Sabine Pass LNG and/or any of its Restricted Subsidiaries; and

(14) the incurrence by Sabine Pass LNG or the Guarantors of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (14), not to exceed $25.0 million.

In addition to Permitted Debt described in clauses (1) through (14) above, Sabine Pass LNG may incur additional Indebtedness (other than Parity Secured Debt) (the “Additional Indebtedness”) so long as (i) the Fixed Charge Coverage Ratio for Sabine Pass LNG’s most recently ended four full fiscal quarters (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) for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or preferred stock is issued, as the case may be, would have been at least 2.0 to 1, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock or preferred stock had been issued, as the case may be, at the beginning of such period and (ii) Sabine Pass LNG has received written confirmation from each Credit Rating Agency that no Ratings Decline will occur as a result of the incurrence of the Additional Indebtedness.

For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of Indebtedness meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (14) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, Sabine Pass LNG will be permitted to classify such item of Indebtedness on the date of its incurrence, or later reclassify all or a portion of such item of Indebtedness, in any manner that complies with this covenant. The accrual of interest, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, the reclassification of preferred stock as Indebtedness due to a change in accounting principles, and the payment of dividends on Disqualified Stock in the form of additional shares of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant; provided, in each such case, that the amount of any such accrual, accretion or payment is included in Fixed Charges of Sabine Pass LNG as accrued. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that Sabine Pass LNG or any Restricted Subsidiary may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in exchange rates or currency values.

The amount of any Indebtedness outstanding as of any date will be:

(1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;

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(2) in respect of Indebtedness of another Person secured by a Lien on the assets of the specified Person, the lesser of:

(a) the Fair Market Value of such asset at the date of determination; and

(b) the amount of the Indebtedness of the other Person; and

(3) the principal amount of the Indebtedness, in the case of any other Indebtedness.

Liens

Sabine Pass LNG will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, assume or suffer to exist any Lien securing Indebtedness on any asset now owned or hereafter acquired, except Permitted Liens.

Dividend and Other Payment Restrictions Affecting Subsidiaries

Sabine Pass LNG will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1) (x) pay dividends or make any other distributions on its Capital Stock to Sabine Pass LNG or any of its Restricted Subsidiaries, or with respect to any other interest or participation in, or measured by, its profits, or (y) pay any indebtedness owed to Sabine Pass LNG or any of its Restricted Subsidiaries;

(2) make loans or advances to Sabine Pass LNG or any of its Restricted Subsidiaries; or

(3) sell, lease or transfer any of its properties or assets to Sabine Pass LNG or any of its Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1) agreements or instruments governing existing indebtedness as in effect on the Issue Date, the Assumption Agreement or Settlement Agreement and any amendments, restatements, modifications, increases, renewals, supplements, refundings, replacements or refinancings of those agreements or instruments; provided that the amendments, restatements, modifications, increases, renewals, supplements, refundings, replacements or refinancings are no more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements or instruments on the Issue Date;

(2) the indenture, the notes, the Note Guarantees and the Security Documents;

(3) applicable law, rule, regulation or order;

(4) customary non-assignment provisions in contracts and licenses entered into in the ordinary course of business;

(5) purchase money obligations for property acquired in the ordinary course of business and Capital Lease Obligations that impose restrictions on the property purchased or leased of the nature described in clause (3) of the preceding paragraph;

(6) any agreement for the sale or other disposition of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending the sale or other disposition;

(7) Permitted Debt, including Permitted Refinancing Indebtedness; provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

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(8) Liens permitted to be incurred under the provisions of the covenant described above under the caption “—Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;

(9) provisions limiting the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements, security agreements, mortgages, purchase money agreements and other similar agreements or instruments entered into with the approval of the Board of Directors of the General Partner, which limitation is applicable only to the assets that are the subject of such agreements;

(10) Interest Rate and Currency Hedges permitted from time to time under the indenture; and

(11) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business.

Merger, Consolidation or Sale of Assets

Sabine Pass LNG will not, directly or indirectly, consolidate, amalgamate or merge with or into another Person (regardless of whether Sabine Pass LNG is the surviving corporation), convert into another form of entity or continue in another jurisdiction; or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the properties or assets of Sabine Pass LNG and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person, unless:

(1) either: (a) Sabine Pass LNG is the surviving entity; or (b) the Person formed by or surviving any such consolidation, amalgamation or merger or resulting from such conversion (if other than Sabine Pass LNG) or to which such sale, assignment, transfer, conveyance or other disposition has been made is a corporation, limited liability company or partnership organized or existing under the laws of the United States, any state of the United States or the District of Columbia;

(2) the Person formed by or surviving any such conversion, consolidation, amalgamation, or merger (if other than Sabine Pass LNG) or the Person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all the obligations of Sabine Pass LNG under the notes, the indenture and the registration rights agreement and the Security Documents pursuant to agreements reasonably satisfactory to the Trustee;

(3) immediately after such transaction or transactions, no Default or Event of Default exists; and

(4) Sabine Pass LNG or the Person formed by or surviving any such consolidation, amalgamation or merger (if other than Sabine Pass LNG), or to which such sale, assignment, transfer, conveyance or other disposition has been made would, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock.”

The surviving entity will succeed to, and be substituted for, and may exercise every right and power of, Sabine Pass LNG under the indenture, but, in the case of a lease of all or substantially all of its assets, Sabine Pass LNG will not be released from the obligation to pay the principal of and interest on the notes.

In addition, Sabine Pass LNG will not, directly or indirectly, lease all or substantially all of the properties and assets of it and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to any other Person.

This “Merger, Consolidation or Sale of Assets” covenant will not apply to:

(1) a merger of Sabine Pass LNG with an Affiliate solely for the purpose of changing the jurisdiction of organization of Sabine Pass LNG to another jurisdiction; or

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(2) any consolidation or merger, or any sale, assignment, transfer, conveyance, lease or other disposition of assets between or among Sabine Pass LNG and its Restricted Subsidiaries.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the property or assets of a Person.

Transactions with Affiliates

Sabine Pass LNG will not, and will not permit any of its Restricted Subsidiaries to, enter into any transaction that is otherwise permitted hereunder with or the benefit of an Affiliate (including guarantees and assumptions of obligations of an Affiliate) (each, an “Affiliate Transaction”), except:

(1) to the extent required by applicable law;

(2) to the extent required or contemplated by the O&M Agreement, the Management Services Agreement, the J & S Cheniere Terminal Use Agreement, the Cheniere Marketing TUA, J & S Cheniere Potential TUA Letter, State Tax Sharing Agreement or the Assumption Agreement;

(3) upon terms no less favorable to Sabine Pass LNG than would be obtained in a comparable arm’s-length transaction with a Person that is not an Affiliate, or, if no comparable arm’s-length transaction with a Person that is not an Affiliate is available, then on terms that are determined by the Board of Directors of the General Partner to be fair in light of all factors considered by said Board of Directors to be pertinent to Sabine Pass LNG;

(4) for any Project processing or use agreement with an Affiliate of Sabine Pass LNG; provided that the terms of such agreement provide for the recovery of at least the incremental Operation and Maintenance Expenses associated with operations pursuant to such agreement and Sabine Pass LNG has entered into the required Security Documents; and

(5) Subordinated Loans between or among Sabine Pass LNG, any of its Restricted Subsidiaries and/or any of their Affiliates.

Prior to entering into any agreement with an Affiliate, Sabine Pass LNG shall deliver to the Collateral Trustee a certificate of an Authorized Officer as to the satisfaction of the applicable condition set forth in clauses (2), (3), (4) and (5) above.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(1) any employment agreement, employee benefit plan, officer or director indemnification agreement or any similar arrangement entered into by Sabine Pass LNG or any of its Restricted Subsidiaries in the ordinary course of business and payments pursuant thereto;

(2) transactions between or among Sabine Pass LNG and/or its Restricted Subsidiaries;

(3) transactions with a Person (other than an Unrestricted Subsidiary of Sabine Pass LNG) that is an Affiliate of Sabine Pass LNG solely because Sabine Pass LNG owns, directly or through a Restricted Subsidiary, an Equity Interest in, or controls, such Person;

(4) payment of reasonable directors’ fees to Persons who are not otherwise Affiliates of Sabine Pass LNG;

(5) any issuance of Equity Interests (other than Disqualified Stock) of Sabine Pass LNG to Affiliates of Sabine Pass LNG;

(6) any Permitted Investments or Restricted Payments that do not violate the provisions of the indenture described above under the caption “—Restricted Payments”;

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(7) Permitted Payments to Parent; and

(8) any contracts, agreements or understandings existing as of the Issue Date or disclosed in this prospectus, and any amendments to or replacements of such contracts, agreements or understandings so long as any such amendment or replacement is not more disadvantageous to Sabine Pass LNG or to the holders of the notes in any material respect than the original agreement as in effect on the Issue Date.

Business Activities

Sabine Pass LNG will not, and will not permit any of its Restricted Subsidiaries to, engage in any business other than Permitted Businesses, except to such extent as would not be material to Sabine Pass LNG and its Restricted Subsidiaries taken as a whole.

Additional Note Guarantees

If (a) Sabine Pass LNG or any of its Restricted Subsidiaries acquires or creates another Domestic Subsidiary after the date of the indenture, and (b) that newly acquired or created Domestic Subsidiary is or becomes obligated with respect to any Indebtedness, then such Domestic Subsidiary will become a Guarantor and execute a supplemental indenture and deliver an opinion of counsel satisfactory to the Trustee within 15 business days of the date on which the conditions in both (a) and (b) above were satisfied; provided that any Domestic Restricted Subsidiary that constitutes an Immaterial Subsidiary need not become a Guarantor until such time as it ceases to be an Immaterial Subsidiary.

Designation of Restricted and Unrestricted Subsidiaries

The Board of Directors of the General Partner may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by Sabine Pass LNG and its Restricted Subsidiaries in the Subsidiary designated as Unrestricted will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the covenant described above under the caption “—Restricted Payments” or under one or more clauses of the definition of Permitted Investments, as determined by Sabine Pass LNG. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.

Any designation of a Subsidiary of Sabine Pass LNG as an Unrestricted Subsidiary will be evidenced to the Trustee by filing with the Trustee a certified copy of a resolution of the Board of Directors of the General Partner giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of Sabine Pass LNG as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock,” Sabine Pass LNG will be in default of such covenant. The Board of Directors of the General Partner may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of Sabine Pass LNG; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of Sabine Pass LNG of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period; and (2) no Default or Event of Default would be in existence following such designation.

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Limitation on Sale and Leaseback Transactions

Sabine Pass LNG will not, and will not permit any of its Restricted Subsidiaries to, enter into any sale and leaseback transaction; provided that Sabine Pass LNG and any of its Restricted Subsidiaries may enter into a sale and leaseback transaction if:

(1) Sabine Pass LNG or that Restricted Subsidiary, as applicable, could have (a) incurred Indebtedness in an amount equal to the Attributable Debt relating to such sale and leaseback transaction under the Fixed Charge Coverage Ratio test described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock” and (b) incurred a Lien to secure such Indebtedness pursuant to the covenant described above under the caption “—Liens”;

(2) the gross cash proceeds of that sale and leaseback transaction are at least equal to the Fair Market Value, as determined in good faith by the Board of Directors of the General Partner and set forth in an officers’ certificate delivered to the Trustee, of the property that is the subject of that sale and leaseback transaction; and

(3) the transfer of assets in that sale and leaseback transaction is permitted by, and Sabine Pass LNG applies the proceeds of such transaction in compliance with, the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales.”

Advances to Subsidiaries

All advances to Restricted Subsidiaries made by Sabine Pass LNG will be evidenced by intercompany notes in favor of Sabine Pass LNG. These intercompany notes will be pledged pursuant to the pledge agreements as Shared Collateral to secure the notes. Each intercompany note will be payable upon demand and will bear interest at the weighted average interest rate on the notes and will be subordinated in right of payment to all existing Senior Debt of the Restricted Subsidiary to which the loan is made. “Senior Debt” of Subsidiaries for the purposes of the intercompany notes will be defined as all Indebtedness of the Restricted Subsidiaries that is not specifically by its terms madepari passu with or junior to the intercompany notes. A form of intercompany note will be attached as an exhibit to the indenture. Repayments of principal with respect to any intercompany notes will be required to be deposited in the Revenue Account for application in accordance with the provisions set forth under “—Post-Completion Account Flows—Revenue Account” above.

Sabine Pass LNG will not permit any Restricted Subsidiary in respect of which Sabine Pass LNG is a creditor by virtue of an intercompany note to incur any Indebtedness that is subordinate or junior in right of payment to any Senior Debt of such Restricted Subsidiary and senior in any respect in right of payment to any intercompany note.

Payments for Consent

Sabine Pass LNG will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, pay or cause to be paid any consideration to or for the benefit of any holder of notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture or the notes unless such consideration is offered to be paid and is paid to all holders of the notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or agreement.

Maintenance of Existence

Subject to the rights of Sabine Pass LNG under “—Merger, Consolidation or Sale of Assets,” Sabine Pass LNG shall do all things necessary to maintain: (i) its corporate, limited liability company or partnership, as applicable, existence in its jurisdiction of organization; provided, that the foregoing shall not prohibit conversion into another form of entity or continuation in another jurisdiction and (ii) the power and authority (corporate and otherwise) necessary under the applicable law to own its properties and to carry on the business of the Project.

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Each of Sabine Pass LNG and the Guarantors shall not dissolve, liquidate, and shall not take any action to amend or modify its corporate constituent or governing documents where such amendment would be adverse in any material respect to the holders of the notes.

Ownership

Sabine Pass LNG will not, and will not permit any of its Restricted Subsidiaries to, and Sabine Pass LNG-LP, LLC and Sabine Pass LNG-GP, Inc. will not, permit either Sabine Pass LNG or any of the Guarantors to issue, sell, transfer or dispose of any Capital Stock of Sabine Pass LNG or any Guarantor, other than to Sabine Pass LNG-LP, LLC and Sabine Pass LNG-GP, Inc., Sabine Pass LNG or one of the Guarantors.

Accounting and Cost Control Systems

Sabine Pass LNG shall maintain, or cause to be maintained, its own management information and cost accounting systems for the Project at all times in accordance with prudent industry practice.

Access

Each of Sabine Pass LNG and its Restricted Subsidiaries shall grant the Collateral Trustee or its designee from time to time, including but not limited to during the pendency of a Default or an Event of Default, reasonable access to all of its books and records, quality control and performance test data, all other data relating to the Project and construction progress and the physical facilities of the Project and an opportunity to discuss accounting matters with Sabine Pass LNG’s independent auditors, provided that all such inspections are conducted during normal business hours in a manner that does not unreasonably disrupt the construction or operation of the Project. The Collateral Trustee shall also have the right to monitor, witness and appraise the construction, testing and operation of the Project. So long as a Default or any Event of Default has occurred and is continuing, the reasonable fees and documented expenses of such persons shall be for the account of Sabine Pass LNG.

Environmental Audits

If the Collateral Trustee reasonably believes that a violation or threat of violation of any environmental law may have occurred that might reasonably be expected to have a Material Adverse Effect, or if a Default or an Event of Default has occurred, Sabine Pass LNG shall, upon receipt of a written communication setting forth the basis for such belief, grant access to and assist any environmental consultants for the purpose of conducting any environmental compliance audits requested by the Collateral Trustee in its reasonable discretion and all reasonable costs associated with any such audits shall be paid by Sabine Pass LNG and the Guarantors.

Preservation of Assets

Each of Sabine Pass LNG and its Restricted Subsidiaries shall maintain its assets in good repair and shall make such repairs and replacements as are required in accordance with prudent industry practice.

Insurance

Each of Sabine Pass LNG and its Restricted Subsidiaries will keep the Project property of an insurable nature and of a character usually insured, insured with financially sound insurers with all risk property and general liability coverage (including deductibles and exclusions) and in such form and amounts as are customary for project facilities of similar type and scale to the Project (including, prior to Phase 1 Final Completion, delay in start-up coverage and, after Phase 1 Final Completion, business interruption). Sabine Pass LNG will cause with limited exceptions, each insurance policy to name the Collateral Trustee on behalf of the secured parties and the secured parties as additional insureds as their interest may appear.

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Taxes

Each of Sabine Pass LNG and its Restricted Subsidiaries shall (i) file or cause to be filed all tax returns required to be filed by it, and (ii) pay and discharge, before the same shall become delinquent, after giving effect to any applicable extensions, all taxes imposed on it or its property (including interest and penalties) unless such taxes are being contested in good faith and by appropriate proceedings, appropriate reserves are maintained with respect thereto and such proceedings, if adversely determined, could not reasonably be expected to have a Material Adverse Effect. Each of Sabine Pass LNG and its Restricted Subsidiaries shall promptly notify the Collateral Trustee, in reasonable detail, of any material disputes pending between it and any governmental authority relating to taxes.

Compliance with Law

Each of Sabine Pass LNG and its Restricted Subsidiaries shall (i) comply with all applicable laws, rules, regulations and orders of governmental authorities (including without limitation environmental, health and safety, mining, port and railway and native title laws), except where such failure to comply could not reasonably be expected to have a Material Adverse Effect and (ii) notify the Collateral Trustee promptly following the initiation of any proceedings or material disputes with any governmental authority or other parties relating to compliance or noncompliance with any such law, rule, regulation or order.

Safety Precautions

Each of Sabine Pass LNG and its Restricted Subsidiaries shall implement and administer safety, health and environmental procedures for the Project consistent with all applicable environmental, health and safety laws, rules, regulations and orders, including with respect to all contractors and subcontractors, except where the failure to so implement and administer could not reasonably be expected to have a Material Adverse Effect.

Maintenance of Approvals for Transaction Documents

Each of Sabine Pass LNG and its Restricted Subsidiaries shall maintain or cause to be maintained all third-party authorizations that are necessary for (i) the execution, delivery and performance by it of the Material Project Agreements to which it is a party and (ii) the incurrence and guarantee of the notes, as the case may be, in good standing, in full force and effect.

Scope of Work; Engagement of Contractors

Each of Sabine Pass LNG and its Restricted Subsidiaries shall use its commercially reasonable efforts to perform, or cause to be performed, all work and services required or appropriate (as set forth in the Construction Budget and Schedule) in connection with the design, engineering, construction, testing and commencement of operations of Phase 1.

Construction and Completion of the Project

Each of Sabine Pass LNG and its Restricted Subsidiaries shall use its commercially reasonable efforts to cause the Project to be constructed in all material respects in accordance with the Construction Budget and Schedule and to cause Phase 1 Target Completion to occur on or before March 20, 2009.

Construction Reports

Until the occurrence of Phase 1 Target Completion, Sabine Pass LNG will provide a monthly progress report to the Collateral Trustee within 30 days after the end of each month. Sabine Pass LNG will ensure that the monthly progress reports include the following information:

(1) a comparison of progress in the construction of the Project in the previous month against the Construction Budget and Schedule, as it may be amended from time to time;

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(2) a comparison of project construction expenditures against the Construction Budget and Schedule, as it may be amended from time to time, including a description of any material variations or change orders issued;

(3) any material delays envisaged in the construction of the Project and the reasons for such delay (such as an industrial dispute, shipping delays or weather);

(4) any relevant material invoices relating to the construction of the Project; and

(5) any material disputes or defaults under any material construction contracts.

Changes to the Construction Budget and Schedule

Sabine Pass LNG will notify the Collateral Trustee of any change to the Construction Budget and Schedule which will increase the then existing Construction Budget and Schedule by more than $30,000,000. Sabine Pass LNG and the Guarantors may implement a change to the Construction Budget and Schedule provided that: (a) the change relates to the Project, and (b) if following implementation of any change which, together with any other changes made to the Construction Budget and Schedule will result in a cumulative increase of more than $100,000,000 to the Construction Budget and Schedule relating to Phase 1, the Cost to Complete Test will continue to be satisfied. Any time a change in the Construction Budget and Schedule described in clause (b) of the foregoing sentence is proposed to be made, Sabine Pass LNG must provide the Collateral Trustee with a certificate from a Responsible Officer describing in reasonable detail the nature and cost of the proposed change and certifying that the requirements of the preceding sentence are satisfied.

Material Project Agreements

Each of Sabine Pass LNG and its Restricted Subsidiaries shall comply in all material respects with its payment and other material obligations under the Material Project Agreements, except where the failure to so comply could not reasonably be expected to have a Material Adverse Effect. Sabine Pass LNG and the Guarantors must notify the Collateral Trustee when entering into or terminating any Material Project Agreement and provide a copy of any such contract to the Collateral Trustee. Each of Sabine Pass LNG and its Restricted Subsidiaries shall not agree to any material amendment or termination of any Material Project Agreement to which it is or becomes a party unless (i) a copy of such amendment or termination has been delivered to the Collateral Trustee at least 10 Business Days in advance of the effective date thereof along with an officer’s certificate of a Responsible Officer certifying that the proposed amendment or termination could not reasonably be expected to have a Material Adverse Effect or (ii) Sabine Pass LNG has obtained the consent of a majority of the holders of the notes to such amendment or termination; provided, that without the consent of the holders of a majority of the outstanding principal amount of the notes, Sabine Pass LNG will not: (x) take any action under the Cheniere Marketing TUA that would cause or would enable an Anchor Customer to reduce the monthly reservation fee or operating fee; (y) amend a terminal use agreement with an Anchor Customer to decrease the tenor, reduce the monthly reservation fee or operating fee, amend the force majeure provisions, the taxes and regulatory costs sharing provisions, or the agreement termination provisions in a manner adverse to Sabine Pass LNG, or reduce the aggregate amount of any guarantee in respect of such terminal use agreement; or (z) agree to take, or take, title to LNG or natural gas (other than LNG or natural gas to which Sabine Pass LNG has taken title in connection with cool down or retainage or pursuant to any terminal use or similar agreement as a result of the failure of any customer of Sabine Pass LNG to take redelivery of any natural gas at any delivery point) from any Anchor Customer.

Phase 1 Final Completion

When Sabine Pass LNG believes that Phase 1 Final Completion has been achieved, Sabine Pass LNG must deliver to the Collateral Trustee a certificate of a Responsible Officer of Sabine Pass LNG certifying that Phase 1 Final Completion has been achieved and detailing the basis for that conclusion.

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Operation of the Project

Sabine Pass LNG shall (i) cause the Project to be operated, repaired and maintained at all times in substantial accordance with prudent industry practice and the Material Project Agreements, (ii) maintain or caused to be maintained such spare parts and inventory as are consistent with the Material Project Agreements and prudent industry practice and (iii) maintain or cause to be maintained at the Project site a complete set of plans and specifications for the Project.

Technology

Sabine Pass LNG shall (i) take all such reasonable actions as may be necessary to ensure that it possesses, or has the right to use, all licenses and other rights with respect to technology prior to Project Completion (or at such earlier time as may be required under the circumstances), and (ii) maintain in place all licenses and other rights with respect to technology, in each case to the extent necessary for the development, construction, operation or maintenance of the Project at any time, except where the failure to take such actions or maintain such licenses or rights could not reasonably be expected to have a Material Adverse Effect.

Preservation of Security Interests

Each of Sabine Pass LNG and its Restricted Subsidiaries shall preserve, maintain and perfect the first priority security interests subject to Permitted Liens granted under the Security Documents and preserve and protect the Collateral as set forth in the Security Documents.

Accounts

Sabine Pass LNG shall cause the Project Accounts to be established and maintained at all times in accordance with the indenture, shall maintain no bank accounts other than the Project Accounts and checking, demand deposit or similar accounts with any financial institutions and shall make no transfer, deposit or withdrawal from any Project Account, except in each case as specifically permitted in the indenture.

Credit Rating Agencies

Sabine Pass LNG shall use its commercially reasonable efforts to cause the notes to be rated by at least two Credit Rating Agencies. If one of the two Credit Rating Agencies ceases to be a “nationally recognized statistical rating organization” registered with the SEC or ceases to be in the business of rating securities of the type and nature of the notes, Sabine Pass LNG and the Guarantors may replace the rating received from it with a rating from any other “nationally recognized statistical rating organization” in the business of rating securities of the type and nature of the notes.

Reports

After Sabine Pass LNG becomes subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, then Sabine Pass LNG shall file with the Trustee, and the Trustee shall provide noteholders, within 15 days after it files them with the SEC, copies of its annual reports and of the information, documents and other reports (or copies of such portions of any of the foregoing as the SEC may by rules and regulations prescribe) that Sabine Pass LNG is required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act.

As long as Sabine Pass LNG is not subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, nor is exempt from reporting pursuant to Rule 12g3-2(b) under the Exchange Act and the notes are “restricted securities” within the meaning of Rule 144 under the Securities Act, upon the request of a noteholder who is a “qualified institutional buyer” (as defined in Rule 144A) or any owner of a beneficial interest in a note who is a “qualified institutional buyer” (as defined in Rule 144A), Sabine Pass LNG shall promptly

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furnish or cause to be furnished “Rule 144A Information” (as defined herein) to such Noteholder or Beneficial Owner or to a prospective purchaser of such note who is a “qualified institutional buyer” (as defined in Rule 144A) designed by such noteholder or Beneficial Owner who is a “qualified institutional buyer” (as defined in Rule 144A). “Rule 144A Information” shall be such information as is specified pursuant to Rule 144A(d)(4) under the Securities Act (or any successor provision thereto).

So long as any of the notes are outstanding, in addition to the requirement to furnish Rule 144A Information as provided in the preceding paragraph, Sabine Pass LNG shall furnish or cause to be furnished to Noteholders and (upon the request thereof delivered to Sabine Pass LNG or the Trustee) to holders of an interest in any Global Note (i) annual consolidated financial statements of Sabine Pass LNG prepared in accordance with GAAP (together with notes thereto and a report thereon by an independent accountant of established national reputation), such statements to be so furnished within 105 days after the end of the fiscal year covered thereby and (ii) unaudited consolidated financial statements of Sabine Pass LNG for each of the first three fiscal quarters of each fiscal year of Sabine Pass LNG and the corresponding quarter and year-to-year period of the prior year prepared in all material respects on a basis consistent with the annual financial statements furnished pursuant to clause (i) of this paragraph, such statements to be so furnished within 60 days after the end of each such quarter.

Events of Default and Remedies

Each of the following is an “Event of Default”:

(1) default for 30 days in the payment when due of interest on, or Additional Interest, if any, with respect to, the notes;

(2) default in payment when due of the principal of, or premium, if any, on the notes;

(3) failure by Sabine Pass LNG to comply with its obligations described under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” or to consummate a purchase of notes when required pursuant to the covenants described under the captions “—Repurchase at the Option of Holders—Change of Control” or “—Repurchase at the Option of Holders—Asset Sales;”

(4) failure by Sabine Pass LNG or any of its Restricted Subsidiaries for 30 days to comply with the provisions described under the captions “—Certain Covenants—Restricted Payments” or “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” or to comply with the provisions described under the captions “—Repurchase at the Option of Holders—Change of Control” or “—Repurchase at the Option of Holders—Asset Sales” to the extent not described in clause (3) above;

(5) failure by Sabine Pass LNG or any of its Restricted Subsidiaries for 60 days after notice from the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes to comply with any of the other agreements in the indenture, the Security Documents or the notes unless covered by another Event of Default;

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by Sabine Pass LNG or any of its Restricted Subsidiaries (or the payment of which is guaranteed by Sabine Pass LNG or any of its Restricted Subsidiaries) whether such Indebtedness or Guarantee now exists, or is created after the Issue Date, if that default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a “Payment Default”); or

(b) results in the acceleration of such Indebtedness prior to its express maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which

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has been so accelerated, aggregates $25.0 million or more; but only if such Indebtedness remains unpaid or the acceleration unrescinded;

(7) any final judgment or decree (to the extent not covered by insurance) for the payment of money in excess of $25.0 million is entered against Sabine Pass LNG or any of its Restricted Subsidiaries and is not paid or discharged, and there is any period of 60 consecutive days following entry of such final judgment or decree during which a stay of enforcement of such final judgment or decree, by reason of pending appeal or otherwise, is not in effect;

(8) breach by Sabine Pass LNG or any of its Restricted Subsidiaries of any material representation or warranty or agreement in the Security Documents unless remedied within 60 days of Sabine Pass LNG obtaining knowledge of such breach;

(9) except as permitted by the indenture, any Security Document of the General Partner, the Limited Partner, Sabine Pass LNG or of any Guarantor that is a Significant Subsidiary or any group of Guarantors that, taken together, would constitute a Significant Subsidiary is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or any such Pledgor, or any Person acting on behalf of any such Pledgor, denies or disaffirms its obligations under the Security Document to which it is a party or shall cease to grant the holders any of the Collateral or rights purported to be granted thereunder;

(10) the failure by Sabine Pass LNG or any Guarantor to comply in all material respects with its payment and other material obligations under a Material Project Agreement and within 60 days after actual knowledge by Sabine Pass LNG or any Guarantor of such failure to comply, such failure has not been remedied by Sabine Pass LNG or the relevant Guarantor (as applicable) within 60 days or if not capable of cure within 60 days, Sabine Pass LNG or such Guarantor has commenced curing such default within 60 days and diligently pursues such cure; provided such cure is completed within 180 days of such knowledge;

(11) except as permitted by the indenture, any Note Guarantee of any Guarantor that is a Significant Subsidiary or any group of Guarantors that, taken together, would constitute a Significant Subsidiary is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or any such Guarantor, or any Person acting on behalf of any such Guarantor, denies or disaffirms its obligations under its Note Guarantee;

(12) the Project is abandoned in whole; and

(13) certain events of bankruptcy or insolvency described in the indenture with respect to Sabine Pass LNG or any of its Restricted Subsidiaries that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

The indenture contains a provision providing that in the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to Sabine Pass LNG, any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding notes will become due and payable immediately without further action or notice. However, the effect of such provision may be limited by applicable laws. If any other Event of Default occurs and is continuing, the Trustee or the holders of at least 25% in principal amount of the then outstanding notes may declare all the notes to be due and payable immediately by notice in writing to Sabine Pass LNG specifying the Event of Default.

Subject to certain limitations, holders of a majority in aggregate principal amount of the then outstanding notes may direct the Trustee in its exercise of any trust or power. The Trustee may withhold from holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal, interest or premium or Additional Interest, if any.

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Subject to the provisions of the indenture relating to the duties of the Trustee, in case an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the indenture at the request or direction of any holders of notes unless such holders have offered to the Trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest or Additional Interest, if any, when due, no holder of a note may pursue any remedy with respect to the indenture or the notes unless:

(1) such holder has previously given the Trustee notice that an Event of Default is continuing;

(2) holders of at least 25% in aggregate principal amount of the then outstanding notes have requested the Trustee to pursue the remedy;

(3) such holders have offered the Trustee reasonable security or indemnity against any loss, liability or expense;

(4) the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5) holders of a majority in aggregate principal amount of the then outstanding notes have not given the Trustee a direction inconsistent with such request within such 60-day period.

The holders of a majority in aggregate principal amount of the then outstanding notes by notice to the Trustee may, on behalf of the holders of all of the notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under the indenture except a continuing Default or Event of Default in the payment of interest or premium or Additional Interest, if any, on, or the principal of, the notes.

Sabine Pass LNG is required to deliver to the Trustee annually a statement regarding compliance with the indenture. Upon becoming aware of any Default or Event of Default, Sabine Pass LNG is required to deliver to the Trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator, member, partner or stockholder of Sabine Pass LNG or any Guarantor (including, without limitation, the General Partner, the Limited Partner and the Parent), as such, will have any liability for any obligations of Sabine Pass LNG or the Guarantors under the notes, the indenture, the Note Guarantees, the Security Documents or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Legal Defeasance and Covenant Defeasance

Sabine Pass LNG may at any time, at the option of the Board of Directors of its General Partner evidenced by a resolution set forth in an officers’ certificate, elect to have all of its obligations discharged with respect to the outstanding notes and all obligations of the Guarantors discharged with respect to their Note Guarantees (“Legal Defeasance”) except for:

(1) the rights of holders of outstanding notes to receive payments in respect of the principal of, or interest or premium and Additional Interest, if any, on, such notes when such payments are due from the trust referred to below;

(2) Sabine Pass LNG’s obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the Trustee, and Sabine Pass LNG’s and the Guarantors’ obligations in connection therewith; and

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(4) the Legal Defeasance and Covenant Defeasance provisions of the indenture.

In addition, Sabine Pass LNG may, at its option and at any time, elect to have the obligations of Sabine Pass LNG and the Guarantors released with respect to certain covenants (including its obligation to make Change of Control Offers and Asset Sale Offers) that are described in the indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, receivership, rehabilitation and insolvency events) described under “—Events of Default and Remedies” will no longer constitute an Event of Default with respect to the notes.

In order to exercise either Legal Defeasance or Covenant Defeasance:

(1) Sabine Pass LNG must irrevocably deposit with the Trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants, to pay the principal of, or interest and premium and Additional Interest, if any, on, the outstanding notes on the stated date for payment thereof or on the applicable redemption date, as the case may be, and Sabine Pass LNG must specify whether the notes are being defeased to such stated date for payment or to a particular redemption date;

(2) in the case of Legal Defeasance, Sabine Pass LNG has delivered to the Trustee an opinion of counsel reasonably acceptable to the Trustee confirming that (a) Sabine Pass LNG has received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the Issue Date, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel will confirm that, the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, Sabine Pass LNG has delivered to the Trustee an opinion of counsel reasonably acceptable to the Trustee confirming that the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit) and the deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which Sabine Pass LNG or any Guarantor is a party or by which Sabine Pass LNG or any Guarantor is bound;

(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which Sabine Pass LNG or any of its Subsidiaries is a party or by which Sabine Pass LNG or any of its Subsidiaries is bound;

(6) Sabine Pass LNG must deliver to the Trustee an officers’ certificate stating that the deposit was not made by Sabine Pass LNG with the intent of preferring the holders of notes over the other creditors of Sabine Pass LNG with the intent of defeating, hindering, delaying or defrauding creditors of Sabine Pass LNG or others;

(7) Sabine Pass LNG must deliver to the Trustee an officers’ certificate stating that all conditions precedent set forth in clauses (1) through (6) of this paragraph have been complied with; and

(8) Sabine Pass LNG must deliver to the Trustee an opinion of counsel (which opinion of counsel may be subject to customary assumptions, qualifications and exclusions), stating that all conditions precedent

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set forth in clauses (2), (3) and (5) of this paragraph have been complied with; provided that the opinion of counsel with respect to clause (5) of this paragraph may be to the knowledge of such counsel.

Amendment, Supplement and Waiver

Except as provided in the next three succeeding paragraphs, the notes or the indenture or the Note Guarantees may be amended or supplemented with the consent of the holders of at least a majority in aggregate principal amount of the notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes), and any existing Default or Event of Default or compliance with any provision of the notes and the indenture or the Note Guarantees may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

Without the consent of each holder of each series of notes affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting holder):

(1) reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any note or alter the provisions with respect to the redemption of the notes; provided,however, that any purchase or repurchase of notes, including pursuant to the covenants described above under the caption “—Repurchase at the Option of Holders,” shall not be deemed a redemption of the notes;

(3) reduce the rate of or change the time for payment of interest, including default interest, on any note;

(4) waive a Default or Event of Default in the payment of principal of, or interest or premium, or Additional Interest, if any, on the notes (except a rescission of acceleration of the notes by the holders of at least a majority in aggregate principal amount of the then outstanding notes and a waiver of the payment default that resulted from such acceleration);

(5) make any note payable in money other than that stated in the notes;

(6) make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of holders of notes to receive payments of principal of, or interest or premium or Additional Interest, if any, on the notes;

(7) waive a redemption payment with respect to any note; provided,however, that any purchase or repurchase of notes, including pursuant to the covenants described above under the caption “—Repurchase at the Option of Holders,” shall not be deemed a redemption of the notes;

(8) release any Guarantor from any of its obligations under its Note Guarantee or the indenture, except in accordance with the terms of the indenture; or

(9) make any change in the preceding amendment and waiver provisions.

Notwithstanding the preceding, without the consent of any holder of notes, Sabine Pass LNG, the Guarantors and the Trustee may amend or supplement the notes and the indenture or the Note Guarantees:

(1) to cure any ambiguity, defect or inconsistency;

(2) to provide for uncertificated notes in addition to or in place of certificated notes;

(3) to provide for the assumption of Sabine Pass LNG’s or a Guarantor’s obligations to holders of notes and Note Guarantees in the case of a merger or consolidation or sale of all or substantially all of Sabine Pass LNG’s or such Guarantor’s assets, as applicable;

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(4) to effect the release of a Guarantor from its Note Guarantee and the termination of such Note Guarantee, all in accordance with the provisions of the indenture governing such release and termination;

(5) to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the indenture of any such holder;

(6) to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;

(7) to conform the text of the indenture, the Note Guarantees or the notes to any provision of this Description of Notes to the extent that such provision in this Description of Notes was intended to be a verbatim recitation of a provision of the indenture or the Note Guarantees or the notes;

(8) to provide for the issuance of additional notes in accordance with the limitations set forth in the indenture as of the date of the indenture;

(9) to add any Note Guarantee; or

(10) to provide for a successor Trustee in accordance with the provisions of the indenture.

No amendment or supplement to the provisions of the indenture or either supplemental indenture described under the caption “—Equal and Ratable Sharing of Shared Collateral by Holders of Parity Secured Debt” will:

(1) be effective unless set forth in a writing signed by the Trustee with the consent of the holders of at least a majority in principal amount of each affected Series of Secured Debt then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, any Series of Secured Debt), voting as a separate class; or

(2) be effective without the written consent of Sabine Pass LNG.

Any such amendment or supplement that imposes any obligation upon the Collateral Trustee or adversely affects the rights of the Collateral Trustee in its individual capacity will become effective only with the consent of the Collateral Trustee.

Amendment of Security Documents

The collateral trust agreement provides that no amendment or supplement to the provisions of any security document will be effective without the approval of the obligors party thereto and the Collateral Trustee acting as directed by an Act of Required Debtholders, except that:

(1) any amendment or supplement that has the effect solely of (i) adding or maintaining Shared Collateral, securing additional Secured Debt that was otherwise permitted by the terms of the Secured Debt Documents to be secured by the Shared Collateral or preserving or perfecting the Liens thereon or the rights of the Collateral Trustee therein; (ii) curing any ambiguity, defect or inconsistency; (iii) providing for the assumption of Sabine Pass LNG’s or another Pledgor’s obligations under any Security Document in the case of a merger or consolidation or sale of all or substantially all of such Pledgor’s assets, as applicable; (iv) releasing a Pledgor from a Security Document and the termination of such Security Document, all in accordance with the provisions of the indenture governing such release and termination; (v) making any change that would provide any additional rights or benefits to the holders of notes or the Collateral Trustee or that does not adversely affect the legal rights under the indenture of any such holder or the Collateral Trustee; (vi) conforming the text of the collateral trust agreement or any other Security Document to any provision of this Description of Notes to the extent that such provision in this Description of Notes was intended to be a verbatim recitation of a provision of the collateral trust agreement or such Security Document; (vii) adding any Security Document, will

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become effective when executed and delivered by the obligors party thereto and the Collateral Trustee as directed by such obligors; and

(2) no amendment or supplement that imposes any obligation upon the Collateral Trustee or any Secured Debt Representative in its individual capacity or adversely affects the rights of the Collateral Trustee or any Secured Debt Representative in its individual capacity will become effective without the additional consent of the Collateral Trustee or such Secured Debt Representative, in its individual capacity.

Any amendment or supplement to the provisions of the Security Documents that releases Shared Collateral will be effective only in accordance with the requirements set forth above under the caption “—Release of Security Interests.”

Satisfaction and Discharge

The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder, when:

(1) either:

(a) all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to Sabine Pass LNG, have been delivered to the Trustee for cancellation; or

(b) all notes that have not been delivered to the Trustee for cancellation have become due and payable by reason of the mailing of a notice of redemption or otherwise or will become due and payable within one year and Sabine Pass LNG or any Guarantor has irrevocably deposited or caused to be deposited with the Trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the notes not delivered to the Trustee for cancellation for principal, premium and Additional Interest, if any, and accrued interest to the date of maturity or redemption;

(2) no Default or Event of Default has occurred and is continuing on the date of the deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit);

(3) such deposit will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which Sabine Pass LNG or any Guarantor is a party or by which Sabine Pass LNG or any Guarantor is bound;

(4) Sabine Pass LNG or any Guarantor has paid or caused to be paid all sums payable by it under the indenture; and

(5) Sabine Pass LNG has delivered irrevocable instructions to the Trustee under the indenture to apply the deposited money toward the payment of the notes at maturity or the redemption date, as the case may be.

In addition, Sabine Pass LNG must deliver to the Trustee (a) an officers’ certificate, stating that all conditions precedent set forth in clauses (1) through (5) above have been satisfied, and (b) an opinion of counsel (which opinion of counsel may be subject to customary assumptions and qualifications), stating that all conditions precedent set forth in clauses (3) and (5) above have been satisfied; provided that the opinion of counsel with respect to clause (3) above may be to the knowledge of such counsel.

Governing Law

The indenture, the notes and the Notes Guarantees will be governed by the laws of the State of New York.

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Concerning the Trustee

If the Trustee becomes a creditor of Sabine Pass LNG or any Guarantor, the indenture limits the right of the Trustee to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as Trustee (if the indenture has been qualified under the Trust Indenture Act) or resign.

The holders of a majority in aggregate principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee, subject to certain exceptions. The indenture provides that in case an Event of Default occurs and is continuing, the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the Trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any holder of notes, unless such holder has offered to the Trustee security and indemnity satisfactory to it against any loss, liability or expense.

Additional Information

Anyone who receives this prospectus may obtain a copy of the indenture and Security Documents without charge by writing to Sabine Pass LNG, L.P., 717 Texas Avenue, Suite 3100, Houston, Texas 77002, USA, Attention: Corporate Secretary.

Book-Entry, Delivery and Form

Except as set forth below, the notes will be issued in registered, global form in minimum denominations of $100,000 and integral multiples of $1,000 in excess of $100,000.

The notes initially will be represented by one or more notes in registered, global form without interest coupons (collectively, the “Global Notes”). The Global Notes will be deposited upon issuance with the Trustee as custodian for The Depository Trust Company (“DTC”), in New York, New York, and registered in the name of DTC or its nominee, in each case, for credit to an account of a direct or indirect participant in DTC as described below. The Global Notes may also be held through the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”) (as indirect participants in DTC).

Except as set forth below, the Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for definitive notes in registered certificated form (“Certificated Notes”) except in the limited circumstances described below. See “—Exchange of Global Notes for Certificated Notes.” Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of notes in certificated form. Transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. Sabine Pass LNG takes no responsibility for these operations and procedures and urges investors to contact the system or their participants directly to discuss these matters.

DTC has advised Sabine Pass LNG that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement

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of transactions in those securities between the Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised Sabine Pass LNG that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of the Participants designated by the initial purchasers with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interest in the Global Notes).

Owners of interest in the Global Notes who are Participants may hold their interests therein directly through DTC. Owners of interest in the Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants. Investors in the Regulation S Global Notes must initially hold their interests therein through Euroclear or Clearstream, if they are participants in such systems, or indirectly through organizations that are participants. Euroclear and Clearstream will hold interests in the Global Notes on behalf of their participants through customers’ securities accounts in their respective names on the books of their respective depositories, which are Euroclear Bank S.A./N.V., as operator of Euroclear, and Citibank, N.A., as operator of Clearstream. All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems. The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of the Participants, which in turn act on behalf of the Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or “holders” thereof under the indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, and Additional Interest, if any, on, a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, Sabine Pass LNG and the Trustee will treat the Persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither Sabine Pass LNG, the Trustee nor any agent of Sabine Pass LNG or the Trustee has or will have any responsibility or liability for:

(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interest in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

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DTC has advised Sabine Pass LNG that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe that it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the Beneficial Owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee or Sabine Pass LNG. Neither Sabine Pass LNG nor the Trustee will be liable for any delay by DTC or any of the Participants or the Indirect Participants in identifying the Beneficial Owners of the notes, and Sabine Pass LNG and the Trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Transfers between the Participants will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Cross-market transfers between the Participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised Sabine Pass LNG that it will take any action permitted to be taken by a holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for legended notes in certificated form, and to distribute such notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. None of Sabine Pass LNG, the Trustee and any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes if:

(1) DTC (a) notifies Sabine Pass LNG that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and, in either case, Sabine Pass LNG fails to appoint a successor depositary;

(2) Sabine Pass LNG, at its option, notifies the Trustee in writing that it elects to cause the issuance of the Certificated Notes; or

(3) there has occurred and is continuing a Default or Event of Default with respect to the notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the Trustee by or on behalf of DTC in accordance with the indenture. In all cases, Certificated

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Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).

Same Day Settlement and Payment

Sabine Pass LNG (including the Collateral Trustee in respect of amounts withdrawn from the Accounts to make payments) will make payments in respect of the notes represented by the Global Notes (including principal, premium, if any, interest and Additional Interest, if any) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. Sabine Pass LNG will make all payments of principal, interest and premium, if any, and Additional Interest, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the holders of the Certificated Notes or, if no such account is specified, by mailing a check to each such holder’s registered address. The notes represented by the Global Notes are expected to be eligible to trade in The PORTAL^SM Market and to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds. Sabine Pass LNG expects that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised Sabine Pass LNG that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.

Certain Definitions

Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all defined terms used therein, as well as any other capitalized terms used herein for which no definition is provided.

“Acceptable Guarantee” means an unconditional guarantee, from an entity with long term unsecured and unguaranteed senior debt rated not less than A from S&P and A2 from Moody’s.

“Acceptable Letter of Credit” means an irrevocable letter of credit from a bank or trust company with a combined capital and surplus of at least $1,000,000,000 whose long term unsecured and unguaranteed senior debt rated not less than A from S&P and A2 from Moody’s.

“Acquired Debt” means, with respect to any specified Person:

(1) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person; and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

“Act of Required Debtholders” means, as to any matter at any time prior to the Discharge of the Parity Secured Debt, a direction in writing delivered to the Collateral Trustee by or with the written consent of the holders of more than 50% of the sum of:

(a) the aggregate outstanding principal amount of Parity Secured Debt; and

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(b) other than in connection with the exercise of remedies, the aggregate unfunded commitments to extend credit which, when funded, would constitute Parity Secured Debt.

For purposes of this definition, (a) Parity Secured Debt registered in the name of, or beneficially owned by, Sabine Pass LNG or any Affiliate of Sabine Pass LNG (other than notes held by any Person that is an Affiliate of Sabine Pass LNG as of the date of the indenture and that is regulated by any banking or insurance authority) will be deemed not to be outstanding, and (b) votes will be determined in accordance with the provisions of the Collateral Trust Agreement.

“Additional Interest” means all liquidated damages then owing pursuant to the registration rights agreement.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings. Notwithstanding the foregoing, the definition of “Affiliate” shall not encompass (a) any individual solely by reason of his or her being a director, officer or employee of any Person and (b) the Collateral Trustee or any note holder solely in their capacity as such.

“Anchor Customer” means Total LNG USA, Inc., Chevron U.S.A. Inc. and any replacements for Total LNG USA, Inc. or Chevron USA Inc. having (or having a guarantor with) a credit rating of not less than A/A2 and engaged in the international gas, petroleum or LNG business.

“Applicable Premium” means, with respect to any note on any redemption date, the greater of:

(1) 1.0% of the principal amount of the note; or

(2) the excess of:

(a) the present value at such redemption date of (i) the redemption price of the note plus (ii) all required interest payments due on the note (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(b) the principal amount of the note, if greater.

“Asset Sale” means:

(1) the sale, lease, conveyance or other disposition of any assets or rights; provided that the sale, lease, conveyance or other disposition of all or substantially all of the assets of Sabine Pass LNG and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the caption “—Repurchase at the Option of Holders—Change of Control” and/or the provisions described above under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant; and

(2) the issuance of Equity Interests in any of Sabine Pass LNG’s Restricted Subsidiaries or the sale of Equity Interests in any of its Subsidiaries.

Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:

(1) any single transaction or series of related transactions that involves assets having a Fair Market Value of less than $5.0 million;

(2) a transfer of assets between or among Sabine Pass LNG and any of its Restricted Subsidiaries;

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(3) an issuance of Equity Interests by a Restricted Subsidiary of Sabine Pass LNG to Sabine Pass LNG or to any Restricted Subsidiary of Sabine Pass LNG;

(4) the sale, lease or other disposition of (a) products, services, inventory or accounts receivable in the ordinary course of business or (b) equipment or other assets pursuant to a program for the maintenance or upgrading of such equipment or assets and the disposition of obsolete equipment, equipment that is damaged or worn out or assets no longer needed in the business of Sabine Pass LNG;

(5) the sale or other disposition of cash or Cash Equivalents;

(6) settlement, release, waiver or surrender of contract, tort or other claims in the ordinary course of business or a grant of a Lien not prohibited by the indenture;

(7) a Restricted Payment that does not violate the covenant described above under the caption “—Certain Covenants—Restricted Payments” or a Permitted Investment; and

(8) the sale or other disposition of cool down gas and excess retainage gas.

“Assumption Agreement” means the agreement for the assumption and adoption by the General Partner, the Limited Partner, Cheniere LNG O&M Services, L.P., Sabine Pass LNG and other Affiliates of Sabine Pass LNG of certain obligations under the Settlement Agreement.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP; provided,however, that if such sale and leaseback transaction results in a Capital Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of “Capital Lease Obligation.”

“Authorized Officer” means a Chief Executive Officer, President, Vice President, Chief Financial Officer, Treasurer or Corporate Secretary of the General Partner.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.

“Board of Directors” means:

(1) with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;

(2) with respect to a partnership, the Board of Directors of the general partner of the partnership;

(3) with respect to a limited liability company, the managing member or members or any controlling committee of managing members thereof; and

(4) with respect to any other Person, the board or committee of such Person serving a similar function.

“Business Day” means any day other than a Legal Holiday.

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet prepared in

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accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty.

“Capital Stock” means:

(1) in the case of a corporation, corporate stock;

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.

“Cash Equivalents” means:

(1) United States dollars;

(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than one year from the date of acquisition;

(3) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition thereof and, at the time of acquisition thereof, having a credit rating of “A” or better from either S&P or Moody’s;

(4) certificates of deposit, demand deposit accounts and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers’ acceptances with maturities not exceeding one year and overnight bank deposits, in each case, with any domestic commercial bank having capital and surplus in excess of $500.0 million and a Thomson Bank Watch Rating of “B” or better;

(5) repurchase obligations with a term of not more than 30 days for underlying securities of the types described in clauses (2), (3) and (4) above entered into with any financial institution meeting the qualifications specified in clause (4) above;

(6) commercial paper or tax exempt obligations having one of the two highest ratings obtainable from Moody’s or S&P and, in each case, maturing within one year after the date of acquisition; and

(7) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (6) of this definition or a money market fund or a qualified investment fund (including any such fund for which the Collateral Trustee or any Affiliate thereof acts as an advisor or a manager) given one of the two highest long-term ratings available from S&P or Moody’s.

“Change of Control” means the occurrence of any of the following:

(1) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation or sale or other transfer of equity of any direct or indirect owner of the General Partner of Sabine Pass LNG), in one transaction or a series of related transactions, of all or substantially all of the properties or assets of the General Partner of Sabine Pass LNG to any “person” (as that term is used in Section 13(d) of the Exchange Act);

(2) the adoption of a plan relating to the liquidation or dissolution of Sabine Pass LNG; or

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(3) the consummation of any transaction (including, without limitation, any merger or consolidation, but excluding any person (as defined above) becoming the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of Parent or any successor thereof), the result of which is that any “person” (as defined above), other than Parent or any successor or subsidiary thereof, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the General Partner, measured by voting power rather than number of shares which occurrence is followed by a Ratings Decline within 90 days thereof.

“Cheniere Marketing TUA” means the agreement dated as of the date of the indenture between Cheniere Marketing, Inc. and Sabine Pass LNG.

“Commission” or “SEC” means the United States Securities and Exchange Commission.

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus, without duplication:

(1) any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale, to the extent deducted in computing such Consolidated Net Income; plus

(2) all extraordinary, unusual or non-recurring items of loss or expense to the extent deducted in computing such Consolidated Net Income; plus

(3) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; plus

(4) the Fixed Charges of such Person and its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income; plus

(5) depreciation, amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period) and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, amortization and other non-cash expenses were deducted in computing such Consolidated Net Income; plus

(6) all non-cash charges related to restricted stock and redeemable stock interests granted to officers, directors and employees, to the extent deducted in computing such Consolidated Net Income;minus

(7) non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue in the ordinary course of business, in each case, on a consolidated basis and determined in accordance with GAAP.

“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:

(1) the Net Income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included only to the extent of the amount of dividends or similar distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;

(2) the Net Income of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders;

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(3) the cumulative effect of a change in accounting principles will be excluded; and

(4) any non-cash mark-to-market adjustments to assets or liabilities resulting in unrealized gains or losses in respect of Interest Rate and Currency Hedges (including those resulting from the application of SFAS 133) shall be excluded.

“Construction Account” has the meaning given to such term under the heading “Project Accounts.”

“Construction Budget and Schedule” means the Phase 1 Construction Budget and Schedule and the Phase 2 Construction Budget and Schedule when taken together.

“Cost to Complete Test” means that funds available to Sabine Pass LNG in the Project Accounts together with revenues to be received by Sabine Pass LNG prior to Phase 1 Final Completion, binding equity commitments with respect to funds supported by an Acceptable Letter of Credit or Acceptable Guarantees, anticipated insurance proceeds and/or available borrowings under Indebtedness permitted under the indenture, are sufficient to achieve Phase 1 Final Completion and to pay any principal and interest due and payable on any Indebtedness of Sabine Pass LNG and the Guarantors prior to the achievement of Phase 1 Final Completion.

“Credit Rating Agencies” means Moody’s, S&P and any other “nationally recognized statistical rating organization” registered with the Commission.

“Currency Agreement” means in respect of a Person any foreign exchange contract, currency swap agreement or other similar agreement as to which such Person is a party or a beneficiary.

“Debt Payment Account” has the meaning given to such term under the heading “Project Accounts.”

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case, at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require Sabine Pass LNG to repurchase such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that Sabine Pass LNG may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The amount of Disqualified Stock deemed to be outstanding at any time for purposes of the indenture will be the maximum amount that Sabine Pass LNG and its Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.

“Domestic Subsidiary” means any Restricted Subsidiary of Sabine Pass LNG that was formed under the laws of the United States or any state of the United States or the District of Columbia or that guarantees or otherwise provides direct credit support for any Indebtedness of Sabine Pass LNG.

“DSR Account” has the meaning given to such term under the heading “Project Accounts.”

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

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“Equity Offering” means any issuance or sale of Equity Interests (other than Disqualified Stock) of Sabine Pass LNG to any Person (other than a Restricted Subsidiary of Sabine Pass LNG) or a contribution to the equity capital of Sabine Pass LNG by any Person (other than a Restricted Subsidiary of Sabine Pass LNG).

“Event of Loss” means, whether in respect of a single event or a series of related events, any of the following:

(1) any loss, destruction or damage of the Project;

(2) any actual condemnation, seizure or taking by exercise of the power of eminent domain or otherwise of the Project, or confiscation of the Project or the requisition of the use of the Project in each case by a governmental authority; or

(3) any settlement in lieu of clause (2) above.

“Fair Market Value” means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors of the General Partner (unless otherwise provided in the indenture).

“Fixed Charge Coverage Ratio” means with respect to any specified Person for any period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period. In the event that Fixed Charges are zero and Consolidated Cash Flow is greater than zero, the Fixed Charge Coverage Ratio will be greater than 2.0 to 1.

In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

(1) acquisitions and dispositions of business entities or property and assets constituting a division or line of business of any Person that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date will be given pro forma effect as if they had occurred on the first day of the four-quarter reference period, and Consolidated Cash Flow for such reference period will be calculated on a pro forma basis in good faith on a reasonable basis by a responsible financial or accounting Officer of Sabine Pass LNG;

(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded;

(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;

(4) any Person that is a Restricted Subsidiary on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period;

(5) any Person that is not a Restricted Subsidiary on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period; and

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(6) if any Indebtedness bears a floating rate of interest, the interest expense on such Indebtedness will be calculated as if the rate in effect on the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligation applicable to such Indebtedness if such Hedging Obligation has a remaining term as at the Calculation Date in excess of 12 months).

“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:

(1) Beginning April 1, 2009, the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued, including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings, and net of the effect of all payments made or received pursuant to Interest Rate Agreements; plus

(2) Beginning April 1, 2009, the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus

(3) any interest on Indebtedness of another Person that is guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such Guarantee or Lien is called upon; plus

(4) the product of (a) all dividends, whether paid or accrued and whether or not in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of Sabine Pass (other than Disqualified Stock) or to Sabine Pass or a Restricted Subsidiary of Sabine Pass, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state and local statutory tax rate of such Person, expressed as a decimal, in each case, determined on a consolidated basis in accordance with GAAP.

“GAAP” means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect from time to time.

“General Partner” means Sabine Pass LNG-GP, Inc., a Delaware corporation.

“Government Securities” means securities that are direct obligations of, or obligations guaranteed by, the United States of America for the timely payment of which its full faith and credit is pledged.

“Guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise).

“Guarantors” means each Subsidiary of Sabine Pass LNG that executes a Note Guarantee in accordance with the provisions of the indenture, and each such Person’s respective successors and assigns, in each case, until the Note Guarantee of such Person has been released in accordance with the provisions of the indenture.

“Hedging Obligations” of any Person means the obligations of such Person pursuant to any Interest Rate and Currency Hedges and, in the case of Sabine Pass LNG, commodity hedges relating to the purchase of LNG for cool down of the Project.

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“Holdings Credit Agreement” means the Credit Agreement, dated as of August 31, 2005, among Cheniere LNG Holdings LLC, the lenders party thereto and Credit Suisse, Cayman Islands Branch, as collateral agent and administrative agent.

“Immaterial Subsidiary” means, as of any date, any Restricted Subsidiary whose total assets, as of that date, are less than $1,000,000 and whose total revenues for the most recent 12-month period do not exceed $1,000,000.

“Indebtedness” means, with respect to any specified Person, any indebtedness of such Person (excluding accrued expenses and trade payables), whether or not contingent:

(1) in respect of borrowed money;

(2) evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);

(3) in respect of banker’s acceptances;

(4) representing Capital Lease Obligations or Attributable Debt in respect of sale and leaseback transactions;

(5) representing the balance deferred and unpaid of the purchase price of any property or services due more than six months after such property is acquired or such services are completed; or

(6) representing any Interest Rate and Currency Hedges or commodity hedges relating to the purchase of LNG for cool down of the Project,

if and to the extent any of the preceding items (other than letters of credit, Attributable Debt and Interest Rate and Currency Hedges and such commodity hedges) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes (a) all indebtedness of any other Person, of the types described above in clauses (1) through (6), secured by a Lien on any asset of the specified Person (regardless of whether such indebtedness is assumed by the specified Person) and (b) to the extent not otherwise included, the guarantee by the specified Person of any indebtedness of any other Person, of the types described above in clauses (1) through (6).

Notwithstanding the foregoing, the following shall not constitute Indebtedness:

(a) any indebtedness that has been defeased in accordance with GAAP or defeased pursuant to the deposit of cash or Cash Equivalents (in an amount sufficient to satisfy all obligations relating thereto at maturity or redemption, as applicable, including all payments of interest and premium, if any) in a trust or account created or pledged for the sole benefit of the holders of such indebtedness, and subject to no other Liens, and in accordance with the other applicable terms of the instrument governing such indebtedness;

(b) any obligation arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business; provided,however, that such obligation is extinguished within five Business Days of its incurrence.

“Interest Rate Agreement” means with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

“Interest Rate and Currency Hedges” of any Person means the obligations of such Person pursuant to any Interest Rate Agreement or Currency Agreement.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations), advances or

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capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If Sabine Pass LNG or any Subsidiary of Sabine Pass LNG sells or otherwise disposes of any Equity Interests of any direct or indirect Subsidiary of Sabine Pass LNG such that, after giving effect to any such sale or disposition, such Person is no longer a Subsidiary of Sabine Pass LNG, Sabine Pass LNG will be deemed to have made an Investment on the date of any such sale or disposition equal to the Fair Market Value of Sabine Pass LNG’s Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” The acquisition by Sabine Pass LNG or any Subsidiary of Sabine Pass LNG of a Person that holds an Investment in a third Person will be deemed to be an Investment by Sabine Pass LNG or such Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investments held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments.” Except as otherwise provided in the indenture, the amount of an Investment will be determined at the time the Investment is made and without giving effect to subsequent changes in value.

“Issue Date” means the first date of original issuance of the notes under the indenture.

“J & S Cheniere Potential TUA Letter” means the letter agreement dated as of the date of the indenture among Cheniere Marketing, Inc., Cheniere LNG, Inc. and Sabine Pass LNG.

“J & S Cheniere Terminal Use Agreement” means any terminal use or similar agreement entered into pursuant to the option agreement dated December 23, 2003 between Cheniere LNG Inc. and J & S Cheniere S.A.

“Junior Lien” means a Lien granted by a security document to the Collateral Trustee upon any property of Sabine Pass or any Guarantor that is junior to the Liens securing the Secured Obligations.

“Junior Lien Debt” means: Additional Indebtedness that is secured by a Junior Lien but only if on or before the day on which such Indebtedness is incurred by Sabine Pass LNG such Indebtedness is designated by Sabine Pass LNG, in an officer’s certificate by an Authorized Officer delivered to the Collateral Trustee on or before such date, as Junior Lien Debt for the purposes of each of the Junior Lien Documents and the collateral trust agreement.

“Junior Lien Documents” means all agreements governing, securing or relating to any Junior Lien Obligations.

“Junior Lien Obligations” means the Junior Lien Debt and all other Obligations in respect of Junior Lien Debt.

“Lease Agreements” means the agreements between Sabine Pass LNG and any land owner granting a lease of real property situated in Cameron Parish, Louisiana in connection with the Project.

“Legal Holiday” means a Saturday, a Sunday or a day on which banking institutions in The City of New York or Houston, Texas or at a place of payment are authorized or required by law, regulation or executive order to remain closed.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest.

“Limited Partner” means Sabine Pass LNG-LP, LLC, a Delaware limited liability company.

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“LNG” means liquefied natural gas.

“Management Services Agreement” means the agreement dated February 25, 2005 between Sabine Pass LNG and the General Partner for the management, administration, development and operation of the Project and for the management and administration of Sabine Pass LNG, as amended and in effect from time to time.

“Material Adverse Effect” means any event or condition which has a material adverse effect on the business or financial condition of Sabine Pass LNG or the ability of Sabine Pass LNG to perform its payment obligations under notes.

“Material Project Agreements” means:

(1) the Phase 1 EPC Contract;

(2) any terminal use agreement signed with an Anchor Customer (and any guarantee thereof);

(3) the Management Services Agreement;

(4) the O&M Agreement;

(5) each Omnibus Agreement;

(6) the Lease Agreements; and

(7) any amendment or replacement of (or guarantee or credit support related to) any of the foregoing, from time to time.

“Moody’s” means Moody’s Investors Service, Inc.

“Net Income” means, with respect to any specified Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however:

(1) any gain or loss, together with any related provision for taxes on such gain or loss, realized in connection with: (a) any Asset Sale; or (b) the disposition of any securities by such Person or any of its Restricted Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Restricted Subsidiaries; and

(2) any extraordinary gain or loss, together with any related provision for taxes on such extraordinary gain or loss.

“Net Loss Proceeds” means the aggregate cash proceeds received by Sabine Pass LNG or any of its Restricted Subsidiaries in respect of any Event of Loss, including, without limitation, insurance proceeds, condemnation awards or damages awarded by any judgment, net of:

(1) the direct costs in recovery of such proceeds (including, without limitation, legal, accounting, appraisal and insurance adjuster fees and any relocation expenses incurred as a result thereof);

(2) amounts required to be and actually applied to the repayment of Indebtedness (other than Indebtedness that is subordinated in right of payment to the notes or the Note Guarantees) permitted under the indenture that is secured by a Permitted Lien on the asset or assets that were the subject of such Event of Loss that ranks prior to the security interest of the Collateral Trustee in those assets; and

(3) any taxes or tax distributions paid or payable as a result of the receipt of such cash proceeds.

“Net Proceeds” means the aggregate cash proceeds received by Sabine Pass LNG or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale, taxes paid or payable as a result of the Asset

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Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements.

“Non-Recourse Debt” means Indebtedness:

(1) as to which neither Sabine Pass LNG nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) constitutes the lender;

(2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness of Sabine Pass LNG or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its Stated Maturity; and

(3) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of Sabine Pass or any of its Restricted Subsidiaries.

“Note Documents” means the notes, the indenture, the Note Guarantees and the Security Documents, as amended and in effect from time to time.

“Note Guarantee” means the Guarantee by each Guarantor of Sabine Pass LNG’s obligations under the indenture and the notes, executed pursuant to the provisions of the indenture.

“Obligations” means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness.

“O&M Agreement” means the agreement between Sabine Pass LNG and the Operator for the operation of the Project, as amended and in effect from time to time.

“Omnibus Agreements” means (a) the Omnibus Agreement dated as of September 2, 2004 between Total LNG USA, Inc. and Sabine Pass LNG and (b) the Omnibus Agreement dated as of November 8, 2004 between Sabine Pass LNG and Chevron U.S.A. Inc., as amended and in effect from time to time.

“Operating Account” has the meaning given to such term under the heading “Operating Account.”

“Operation and Maintenance Expenses” means, for any period, the sum, computed without duplication, of the following: (a) general and administrative expenses including expense reimbursements payable to the manager pursuant to the Partnership Agreement and for ordinary course fees and costs of the manager pursuant to the Management Services Agreement plus (b) expenses for operating the Project and maintaining it in good repair and operating condition payable during such period, including the ordinary course fees and costs of the Operator payable pursuant to the O&M Agreement plus (c) insurance costs payable during such period plus (d) applicable sales and excise taxes (if any) payable or reimbursable by Sabine Pass LNG during such period plus (e) franchise taxes payable by Sabine Pass LNG during such period plus (f) property taxes payable by Sabine Pass LNG during such period plus (g) any other direct taxes (if any) payable by Sabine Pass LNG during such period plus (h) costs and fees attendant to the obtaining and maintaining in effect the Government Approvals payable during such period plus (i) legal, accounting and other professional fees attendant to any of the foregoing items payable during such period plus (j) all other cash expenses payable by Sabine Pass LNG in the ordinary course of business. Operation and Maintenance Expenses shall exclude, to the extent included above: (i) payments into any of the Project Accounts during such period, (ii) payments of any kind with respect to Restricted Payments during such period, (iii) depreciation for such period, (iv) any capital expenditure including permitted capital expenditures and (v) any payments of any kind with respect to any restoration during such period.

“Operator” means Cheniere LNG O&M Services, L.P. or such other person from time to time party to the O&M Agreement as ‘Operator’.

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“Parent” means Cheniere Energy, Inc., a Delaware corporation.

“Parity Lien” means a Lien granted by a Security Document to the Collateral Trustee, at any time, upon any property of Sabine Pass LNG or any Guarantor to secure Parity Secured Debt.

“Parity Secured Debt” means the notes issued on the date of the indenture and any other Indebtedness of Sabine Pass LNG (including additional notes), which may be guaranteed by the Guarantors, that is secured equally and ratably with the notes by a Parity Lien that was permitted to be incurred pursuant to clauses (2), (6), (7), (8), (12) and (14) of the definition of Permitted Debt.

“Partnership Agreement” means the Fifth Amended and Restated Agreement of Limited Partnership of Sabine Pass, LNG L.P., effective as of the date of the indenture, as amended and in effect from time to time.

“Permitted Business” means the construction, operation, expansion, reconstruction, debottlenecking, improvement and maintenance of the Project, and all activity necessary or undertaken in connection with the foregoing.

“Permitted Investments” means:

(1) any Investment in Sabine Pass LNG or in a Restricted Subsidiary of Sabine Pass LNG that is a Guarantor and that is engaged in the Permitted Business;

(2) any Investment in Cash Equivalents;

(3) any Investment by Sabine Pass LNG or any Restricted Subsidiary of Sabine Pass LNG in a Person, if as a result of such Investment:

(a) such Person becomes a Restricted Subsidiary of Sabine Pass LNG; or

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, Sabine Pass LNG or a Restricted Subsidiary of Sabine Pass LNG;

(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales;”

(5) any Investment in any Person solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of Sabine Pass LNG or any of its Subsidiaries;

(6) any Investments received in compromise or resolution of (A) obligations of trade creditors or customers that were incurred in the ordinary course of business of Sabine Pass LNG or any of its Restricted Subsidiaries, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; or (B) litigation, arbitration or other disputes with Persons who are not Affiliates;

(7) Investments represented by Hedging Obligations;

(8) advances to or reimbursements of employees for moving, entertainment and travel expenses, drawing accounts and similar expenditures in the ordinary course of business;

(9) loans or advances to employees made in the ordinary course of business of Sabine Pass or any Restricted Subsidiary of Sabine Pass in an aggregate principal amount not to exceed $2.5 million at any one time outstanding;

(10) repurchases of the notes;

(11) advances, deposits and prepayments for purchases of any assets, including any Equity Interests;

(12) advances to customers or suppliers in the ordinary course of business that are, in conformity with GAAP, recorded as accounts receivable, prepaid expenses or deposits on the balance sheet of Sabine

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Pass LNG or its Restricted Subsidiaries and endorsements for collection or deposit arising in the ordinary course of business;

(13) receivables owing to Sabine Pass LNG or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided,however, that such trade terms may include such concessionary trade terms as Sabine Pass LNG or any such Restricted Subsidiary deems reasonable under the circumstances;

(14) Investments received as a result of a foreclosure by Sabine Pass LNG or any of its Restricted Subsidiaries with respect to any secured Investment in default;

(15) surety and performance bonds and workers’ compensation, utility, lease, tax, performance and similar deposits and prepaid expenses in the ordinary course of business;

(16) Guarantees of Indebtedness permitted under the covenant contained under the caption “Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”;

(17) Investments existing on the Issue Date; and

(18) other Investments in any Person having an aggregate Fair Market Value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (18) that are at the time outstanding not to exceed $10.0 million.

“Permitted Liens” means:

(1) Liens in favor of Sabine Pass LNG or any Restricted Subsidiary;

(2) Liens on property of a Person existing at the time such Person is merged with or into or consolidated with Sabine Pass LNG or any Subsidiary of Sabine Pass LNG; provided that such Liens were in existence prior to the contemplation of such merger or consolidation and do not extend to any assets other than those of the Person merged into or consolidated with Sabine Pass LNG or the Subsidiary;

(3) Liens on property (including Capital Stock) existing at the time of acquisition of the property by Sabine Pass LNG or any Subsidiary of Sabine Pass LNG; provided that such Liens were in existence prior to, such acquisition, and not incurred in contemplation of, such acquisition;

(4) bankers’ Liens, rights of setoff and Liens to secure the performance of bids, tenders, trade or governmental contracts, leases, licenses, statutory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature incurred in the ordinary course of business;

(5) Liens to secure Indebtedness (including Capital Lease Obligations) permitted by clauses (2), (6), (7), (8), (12) and (14) of the second paragraph of the covenant entitled “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” covering only the assets acquired with or financed by such Indebtedness;

(6) Liens existing on the Issue Date;

(7) Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings promptly instituted and diligently concluded; provided that any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor;

(8) Liens imposed by law, such as carriers’, warehousemen’s, landlord’s and mechanics’ Liens, in each case, incurred in the ordinary course of business or incident to the development of the Project or any restoration of the Project following an Event of Loss;

(9) survey exceptions, easements or reservations of, or rights of others for, licenses, rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning or other restrictions

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as to the use of real property that were not incurred in connection with Indebtedness and other encumbrances and imperfections to title that do not in the aggregate materially adversely affect the value of said properties they encumber or materially impair their use in the operation of the business of such Person;

(10) Liens created for the benefit of (or to secure) the notes (or the Note Guarantees) and the Assumption Agreement;

(11) Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the indenture; provided,however, that:

(a) the new Lien shall be limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and

(b) the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (x) the outstanding principal amount, or, if greater, committed amount, of the Permitted Refinancing Indebtedness and (y) an amount necessary to pay any fees and expenses, including premiums, related to such renewal, refunding, refinancing, replacement, defeasance or discharge;

(12) To the extent, in each case, not otherwise resulting in an Event of Default, Liens arising by reason of a judgment, decree or court order and any Liens that are required to protect or enforce any rights in any administrative, arbitration or other court proceedings in the ordinary course of business;

(13) Liens contained in purchase and sale agreements limiting the transfer of assets pending the closing of the transactions contemplated thereby;

(14) Liens created in connection with advances or deposits made in connection with the purchase of assets or Equity Interests;

(15) Liens that may be deemed to exist by virtue of contractual provisions that restrict the ability of Sabine Pass LNG or any of its Subsidiaries from granting or permitting to exist Liens on their respective assets;

(16) Liens in favor of the Trustee as provided for in the indenture on money or property held or collected by the Trustee in its capacity as Trustee;

(17) Liens incurred in the ordinary course of business of Sabine Pass LNG or any Subsidiary of Sabine Pass LNG with respect to obligations that do not exceed $10.0 million at any one time outstanding;

(18) Liens referred to in the title policy currently in effect with respect to the Project site;

(19) Liens in respect of rights of or granted by owners of oil and gas estates in and to the Project site; and

(20) Junior Liens.

“Permitted Payments to Parent” means, without duplication as to amounts allowed to be distributed under any other provision of the indenture:

(1) payments to the Parent to permit the Parent to pay reasonable accounting, legal and administrative expenses of the Parent when due, in an aggregate amount not to exceed $1.0 million per calendar year; and

(2) for any fiscal year or portion thereof (the “Tax Year”) of Sabine Pass LNG in which period Sabine Pass LNG is a limited partnership, disregarded entity or other substantially similar pass-through entity for federal and state income tax purposes, distributions to enable the partners of Sabine Pass LNG to make payments of federal, state and local income taxes not covered by the State Tax Sharing Agreement (including quarterly estimated payments thereof) in respect of the taxable income of such partner with respect to Sabine Pass LNG for each such Tax Year (“Tax Distributions”) in an aggregate amount

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equal to the relevant income tax (including any penalties and interest) that Sabine Pass LNG and its Subsidiaries that are treated as pass-through entities for federal and state income tax purposes (“Pass-Through Subsidiaries”) would owe for such Tax Year if Sabine Pass LNG were a corporation subject to federal and state income tax filing a separate tax return or a separate consolidated, combined or unitary return solely with its Pass-Through Subsidiaries, taking into account any carryovers and carrybacks of tax attributes that are generated by and directly allocable to Sabine Pass LNG and its Pass-Through Subsidiaries (such as the applicable net operating losses, tax credits, etc.). In determining the amount of the Tax Distributions, Sabine Pass LNG shall compute its tax liability as if (i) each of Sabine Pass LNG and its Pass-Through Subsidiaries were regular corporate taxpayers, and (ii) Sabine Pass LNG was the common parent corporation during the applicable taxable reporting period. All relevant tax computations shall be made as if Sabine Pass LNG was not related to either the Parent or any of the Parent’s Affiliates. Any Tax Distributions received from Sabine Pass LNG shall be paid to the appropriate taxing authority within 30 days of the receipt of such Tax Distributions.

“Permitted Refinancing Indebtedness” means any Indebtedness of Sabine Pass LNG or any of its Restricted Subsidiaries, any Disqualified Stock of Sabine Pass LNG or any preferred stock of any Restricted Subsidiary issued (a) in exchange for, or the net proceeds of which are used to extend, renew, refund, refinance, replace, defease, discharge or otherwise retire for value, in whole or in part, or (b) constituting an amendment, modification or supplement to or a deferral or renewal of ((a) and (b) above, collectively, a “Refinancing”), any other Indebtedness of Sabine Pass LNG or any of its Restricted Subsidiaries (other than intercompany Indebtedness), any Disqualified Stock of Sabine Pass LNG or any preferred stock of a Restricted Subsidiary in a principal amount or, in the case of Disqualified Stock of Sabine Pass LNG or preferred stock of a Restricted Subsidiary, liquidation preference, not to exceed (after deduction of reasonable and customary fees and expenses incurred in connection with the Refinancing) the lesser of:

(1) the principal amount or, in the case of Disqualified Stock or preferred stock, liquidation preference, of the Indebtedness, Disqualified Stock or preferred stock so Refinanced (plus, in the case of Indebtedness, the amount of premium, if any paid in connection therewith); and

(2) if the Indebtedness being Refinanced was issued with any original issue discount, the accreted value of such Indebtedness (as determined in accordance with GAAP) at the time of such Refinancing.

Notwithstanding the preceding, no Indebtedness, Disqualified Stock or preferred stock will be deemed to be Permitted Refinancing Indebtedness, unless:

(1) such Indebtedness, Disqualified Stock or preferred stock has a final maturity date or redemption date, as applicable, later than the final maturity date or redemption date, as applicable, of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness, Disqualified Stock or preferred stock being Refinanced;

(2) if the Indebtedness, Disqualified Stock or preferred stock being Refinanced is contractually subordinated or otherwise junior in right of payment to the notes, such Indebtedness, Disqualified Stock or preferred stock has a final maturity date or redemption date, as applicable, later than the final maturity date or redemption date, as applicable, of, and is contractually subordinated or otherwise junior in right of payment to, the notes, on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness, Disqualified Stock or preferred stock being Refinanced at the time of the Refinancing; and

(3) such Indebtedness or Disqualified Stock is incurred or issued by Sabine Pass LNG or such Indebtedness, Disqualified Stock or preferred stock is incurred or issued by the Restricted Subsidiary who is the obligor on the Indebtedness being Refinanced or the issuer of the Disqualified Stock or preferred stock being Refinanced.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

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“Phase 1” has the meaning given to such term under the heading “Business” above.

“Phase 2” has the meaning given to such term under the heading “Business” above.

“Phase 2 Completion” means “Final Acceptance” as defined in the Agreement for Engineering, Procurement, Construction and Management of Construction Services of the Sabine Pass LNG Phase 2 Receiving Storage and Regasification Terminal Expansion between Sabine Pass LNG and Bechtel Corporation.

“Phase 1 Construction Budget and Schedule” means, until Phase 1 Final Completion, (a) a budget setting forth, on a monthly basis, the timing and amount of all projected payments of Phase 1 Project Costs through the projected date of Phase 1 Final Completion and (b) a schedule setting forth the proposed engineering, procurement, construction and testing milestone schedule for the development of Phase 1 through the projected date of Phase 1 Final Completion, which budget and schedule shall (i) be certified by Sabine Pass LNG as the best reasonable estimate of the information set forth therein as of the Issue Date and (ii) be consistent with the requirements of the Transaction Documents; provided, that in each of clause (a) and (b), such budget and schedule may be modified from time to time so long as such modification is in conformance with the Phase 1 EPC Contract and the other Transaction Documents.

“Phase 2 Construction Budget and Schedule” means, until Phase 1 Final Completion, (a) a budget setting forth, on a monthly basis, the timing and amount of all projected payments of Phase 2 Project Costs through the projected date of Phase 1 Final Completion and (b) a schedule setting forth the proposed engineering, procurement, construction and testing milestone schedule for the development of Phase 2 through the projected date of final completion for Phase 2, which budget and schedule shall (i) be certified by Sabine Pass LNG as the best reasonable estimate of the information set forth therein as of the Issue Date and (ii) be consistent with the requirements of the Transaction Documents; provided, that in each of clause (a) and (b), such budget and schedule may be modified from time to time so long as such modification is in conformance with the Phase 2 EPC Arrangements and the other Transaction Documents.

“Phase 1 Contractor” means Bechtel Corporation.

“Phase 2 EPC Arrangements” means the arrangements for the engineering, procurement and construction of Phase 2 by Sabine Pass LNG with Bechtel Corporation, Remedial Construction Services, L.P., Diamond LNG LLC and Zachry Construction Corporation, respectively, in connection with the construction of Phase 2.

“Phase 1 EPC Contract” means the lump sum turnkey agreement for the engineering, procurement and construction of Phase 1 by and between Sabine Pass LNG and the Phase 1 Contractor dated as of December 18, 2004, as amended and in effect from time to time.

“Phase 1 Final Completion” has the meaning given to “Final Completion” in the Phase 1 EPC Contract.

“Phase 1 Target Completion” has the meaning given to “Target Completion” in the Phase 1 EPC Contract.

“Phase 1 Project Costs” means all costs, fees, taxes and expenses incurred by Sabine Pass LNG to complete Phase 1 as contemplated by (and consistent with) the Transaction Documents and Government Approvals.

“Phase 2 Project Costs” means all costs, fees, taxes and expenses incurred by Sabine Pass LNG to complete Phase 2 as contemplated by (and consistent with) the Transaction Documents and Government Approvals.

“Pledgors” means the General Partner, the Limited Partner, Sabine Pass LNG and each Subsidiary of Sabine Pass LNG that executes a security document in accordance with the provisions of the indenture, and each such Person’s respective successors and assigns, in each case, until the security document of such Person has been released in accordance with the provisions of the indenture.

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“Project” means the Sabine Pass LNG receiving terminal in Cameron Parish, Louisiana, including associated storage tanks, unloading docks, vaporizers, tugs and related facilities.

“Project Accounts” has the meaning given to such term under the heading “Project Accounts.”

“Project Completion” or “Completion” means the Phase 1 Final Completion and Phase 2 Completion, when taken together.

“Rating Categories” means:

(1) with respect to S&P, any of the following categories: AAA, AA, A, BBB, BB, B, CCC, CC, C and D (or equivalent successor categories); and

(2) with respect to Moody’s, any of the following categories: Aaa, Aa, A, Baa, Ba, B, Caa, Ca, C and D (or equivalent successor categories).

“Ratings Decline” means a decrease in the rating of the notes by either Moody’s or S&P by one or more gradations (including gradations within Rating Categories as well as between Rating Categories) from the initial rating on the Issue Date. In determining whether the rating of the Notes has decreased by one or more gradations, gradations within Ratings Categories, namely + or – for S&P, and 1, 2, and 3 for Moody’s, will be taken into account; for example, in the case of S&P, a rating decline either from BB+ to BB or BB to B+ will constitute a decrease of one gradation.

“Required Debt Payment Amount” means on any date of determination thereof, the amount equal to (i) the aggregate amount of interest on the 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.

“Replacement Assets” means (1) non-current assets that will be used or useful in a Permitted Business or (2) substantially all the assets of a Permitted Business or a majority of the Voting Stock of any Person engaged in a Permitted Business that will become on the date of acquisition thereof a Restricted Subsidiary.

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.

“Revenue Account” has the meaning given to such term under the heading “Project Accounts.”

“S&P” means Standard & Poor’s Ratings Group.

“Secured Debt” means the Parity Secured Debt.

“Secured Debt Documents” means, collectively, the Note Documents, and the indenture or agreement governing each other Series of Secured Debt and all agreements binding on any Obligor related hereto.

“Secured Debt Representative” means the Trustee and each other representative of a Series of Secured Debt.

“Secured Obligations” means the Parity Secured Debt and the Assumption Agreement.

“Secured Debt Termination Date” means the date on which all Secured Debt (including all interest accrued thereon after the commencement of any bankruptcy, insolvency or liquidation proceeding at the rate, including any applicable post-default rate, specified in the applicable Secured Debt Documents, even if such interest is not enforceable, allowable or allowed as a claim in such proceeding) have been paid in full in cash (and/or defeased in accordance with the applicable Secured Debt Documents), all commitments to extend credit under all Secured Debt Documents have terminated or expired and all outstanding letters of credit issued pursuant to any Secured Debt Documents have been cancelled, terminated or cash collateralized.

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“Security Documents” means the collateral trust agreement, the intercreditor agreement, and all security agreements, pledge agreements, collateral assignments, mortgages, deeds of trust, collateral agency agreements, control agreements or other grants or transfers for security executed and delivered by Sabine Pass LNG or any other Pledgor creating (or purporting to create) a Lien upon Shared Collateral in favor of the Collateral Trustee, in each case, as amended, modified, renewed, restated or replaced, in whole or in part, from time to time.

“Senior Debt” means:

(1) all Indebtedness of Sabine Pass LNG or any Guarantor permitted to be incurred under the terms of the indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the notes or any Note Guarantee; and

(2) all Obligations with respect to the items listed in the preceding clause (1).

Notwithstanding anything to the contrary in the preceding, Senior Debt will not include:

(1) any liability for federal, state, local or other taxes owed or owing by Sabine Pass LNG;

(2) any intercompany Indebtedness of Sabine Pass LNG or any of its Subsidiaries to Sabine Pass LNG or any of its Affiliates;

(3) any trade payables;

(4) the portion of any Indebtedness that is incurred in violation of the indenture; or

(5) Indebtedness which is classified as non-recourse in accordance with GAAP or any unsecured claim arising in respect thereof by reason of the application of section 1111(b)(1) of the Bankruptcy Code.

“Series of Secured Debt” means, severally, the notes and each other issue or series of Parity Secured Debt.

“Settlement Agreement” means the Settlement and Purchase Agreement dated as of June 14, 2001 among the Parent, Cheniere FLNG, L.P., Crest Energy L.L.C., Crest Investment Company and Freeport LNG Terminal LLC, as modified by the letter agreement dated February 27, 2003.

“Shared Collateral” means all collateral of whatsoever nature purported to be subject to the Lien of any Security Document.

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the indenture.

“State Tax Sharing Agreement” means the Tax Sharing Agreement dated as of the date of the indenture between Parent and Sabine Pass LNG, without regard to any amendment after the Issue Date unless approved by the Trustee.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the documentation governing such Indebtedness as of the date of the indenture, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“Subordinated Indebtedness” means Indebtedness of Sabine Pass LNG or a Guarantor that is contractually subordinated in right of payment, in any respect (by its terms or the terms of any document or instrument relating thereto), to the notes or the Note Guarantee of such Guarantor, as applicable.

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“Subsidiary” means, with respect to any specified Person:

(1) any corporation, association or other business entity of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency and after giving effect to any voting agreement or stockholders’ agreement that effectively transfers voting power) to vote in the election of directors, managers or Trustees of the corporation, association or other business entity is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof).

“Transaction Documents” means the Note Documents and the Material Project Agreements.

“Treasury Rate” means, as of any redemption date, the yield to maturity as of such redemption date of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to the maturity date; provided,however, that if the period from the redemption date to the maturity date, is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used.

“Unrestricted Subsidiary” means any Subsidiary of Sabine Pass LNG that is designated by the Board of Directors of the General Partner as an Unrestricted Subsidiary pursuant to a resolution of the Board of Directors, but only to the extent that such Subsidiary:

(1) has no Indebtedness other than Non-Recourse Debt;

(2) except as permitted by the covenant described above under the caption “—Certain Covenants—Transactions with Affiliates,” is not party to any agreement, contract, arrangement or understanding with Sabine Pass LNG or any Restricted Subsidiary of Sabine Pass LNG unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to Sabine Pass LNG or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of Sabine Pass LNG;

(3) is a Person with respect to which neither Sabine Pass LNG nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(4) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of Sabine Pass LNG or any of its Restricted Subsidiaries.

“Voting Stock” of any specified Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

(2) the then outstanding principal amount of such Indebtedness.

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UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following discussion describes the material U.S. federal income tax consequences applicable to the exchange of the notes for initial notes in the exchange offer and of the ownership and disposition of the notes. This discussion is not a complete discussion of all the potential tax consequences that may be relevant to you. This discussion is based upon the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations thereunder, published rulings and court decisions, all as in effect on the date of this document, and all of which are subject to change, possibly on a retroactive basis.

For purposes of this discussion, you are a “U.S. holder” if you are a beneficial owner of notes and you are a “U.S. person” for U.S. federal income tax purposes. You are a “non-U.S. holder” if you are a beneficial owner of notes (other than an entity treated as a partnership for U.S. federal income tax purposes) that is not a U.S. holder. A “U.S. person” is:

• an individual citizen or resident of the United States;

• a corporation or other entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States or of any state thereof or the District of Columbia;

• an estate whose income is subject to U.S. federal income taxation regardless of its source; or

• a trust if a U.S. court is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust, or a trust that has a valid election in effect under applicable regulations to be treated as a U.S. person.

If a partnership or other entity treated as a partnership for U.S. federal income tax purposes holds the notes, the tax treatment of a partner will generally depend on the status of the partner and on the activities of the partnership. Partners of partnerships holding notes should consult their tax advisors.

This discussion only applies to holders who hold the notes as capital assets. The tax treatment of holders of the notes may vary depending upon their particular situations. Certain holders, including insurance companies, tax exempt organizations, financial institutions, investors in pass-through entities, expatriates, U.S. holders whose functional currency is not the U.S. dollar, taxpayers subject to the alternative minimum tax, broker-dealers and persons holding the notes as part of a “straddle,” “hedge” or “conversion transaction,” may be subject to special rules not discussed below. This discussion does not address any estate, gift, foreign, state or local taxes. We urge you to consult your own tax advisors regarding the particular U.S. federal income tax consequences to you of holding and disposing of notes, any tax consequences that may arise under the laws of any relevant foreign, state, local, or other taxing jurisdiction or under any applicable tax treaty, as well as possible effects of changes in federal or other tax laws.

The Exchange Offer

The exchange of notes for initial notes pursuant to the exchange offer will not be a taxable transaction for U.S. federal income tax purposes. Holders will not recognize any taxable gain or loss as a result of the exchange offer and will have the same tax basis and holding period in the notes as they had in the initial notes immediately before the exchange.

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U.S. Holders

The following is a summary of the material U.S. federal income tax consequences that will generally apply to you if you are a U.S. holder of the notes. Material consequences to non-U.S. holders of the notes are described under “Non-U.S. Holders” below.

Payments of Interest

Interest on a note generally will be includable in your income as ordinary income at the time the interest is either received or accrued in accordance with your regular method of accounting for U.S. federal income tax purposes. Special rules governing the treatment of discount and premium are discussed below.

Market Discount

If you purchase a note for an amount that is less than its issue price, subject to a de minimis exception, you will be treated as having purchased the note at a “market discount.” In that case, you will be required to treat any payment on, or any gain realized on the sale, exchange, or other disposition of, the note as ordinary income to the extent of the lesser of (i) the amount of such payment or realized gain or (ii) the market discount accrued on the note while held by you and not previously included in income. You also may be required to defer the deduction of all or a portion of any interest paid or accrued on indebtedness incurred or maintained to purchase or carry the note. Alternatively, you may elect (with respect to the note and all your other market discount obligations) to include market discount in income currently as it accrues. Market discount is considered to accrue ratably during the period from the date of acquisition to the maturity date of the note, unless you elect to accrue market discount on the basis of a constant interest rate. Amounts includible in income as market discount are generally treated as ordinary interest income.

Premium

If you purchase a note for an amount that is greater than the sum of all principal amounts payable on the note after your purchase date, you will be treated as having purchased the note with “amortizable bond premium” equal in amount to that excess. You may elect (with respect to the note and all your other obligations with amortizable bond premium) to amortize such premium using a constant yield method over the remaining term of the note and may offset interest income otherwise required to be included in respect to the note during any taxable year by the amortized amount of such excess for the taxable year.

Sale, Exchange, or Other Disposition of the Notes

Upon a sale, exchange, retirement or other taxable disposition of a note, you generally will recognize gain or loss equal to the difference between the amount received upon the sale, exchange, retirement or other taxable disposition (less any amount attributable to accrued interest which will be taxable as ordinary income, if not previously taken into gross income) and your adjusted tax basis in the note at that time.

Subject to the application of the market discount rules described above, gain or loss realized on the sale, taxable exchange, redemption, retirement or other taxable disposition of a note generally will be capital gain or loss, and will be long-term capital gain or loss if, at the time of sale, exchange, retirement or other taxable disposition, the note has been held for more than one year. Under current law, long-term capital gains of certain non-corporate holders are generally taxed at lower rates than items of ordinary income. The deductibility of capital losses is subject to limitations.

Information Reporting and Backup Withholding

In general, information reporting will apply to certain payments of interest on the notes and to the proceeds from the sale or other disposition of a note unless you are an exempt recipient. Additionally, a backup

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withholding tax (currently at a rate of 28%) will apply to such payments if you fail to provide a correct taxpayer identification number or certification of exempt status or fail to report full dividend and interest income or otherwise fail to comply with applicable requirements of the backup withholding rules.

Backup withholding is not an additional tax. If backup withholding applies to you, you may use the amounts withheld as a refund or credit against your U.S. federal income tax liability, as long as you timely provide specific information to the IRS.

Non-U.S. Holders

The following is a general discussion of the material U.S. federal income tax consequences that will generally apply to you if you are a non-U.S. holder of the notes.

Payments of Interest

Payments of interest on a note that is not effectively connected with a U.S. trade or business will not be subject to U.S. federal income tax and withholding of U.S. federal income tax will not be required on that payment if you:

• do not actually or constructively, directly or indirectly, own 10% or more of our capital or profits interests;

• are not a controlled foreign corporation with respect to which we are a related person;

• are not a bank receiving interest on certain loans entered into in the ordinary course of business within the meaning of the Internal Revenue Code; and

• either (1) you certify to us, our payment agent, or the person who would otherwise be required to withhold U.S. federal income tax, on IRS Form W-8BEN or an applicable substitute form, under penalties of perjury, that you are not a U.S. person and provide your name and address, (2) a securities clearing organization, bank or other financial institution that holds customers’ securities in the ordinary course of its trade or business and holds the notes on your behalf certifies to us or our payment agent under penalties of perjury that it, or the financial institution between it and you, has received from you a statement, under penalties of perjury, that you are not a U.S. person and provides us or our payment agent with a copy of such statement, or (3) you hold your notes directly through a “qualified intermediary” and certain other conditions are satisfied.

If you do not satisfy the preceding requirements, your interest on a note that is not effectively connected with a U.S. trade or business would generally be subject to U.S. withholding tax at a flat rate of 30% unless that rate is reduced or eliminated pursuant to an applicable tax treaty (provided specific certification requirements are met).

United States Trade or Business

If you are engaged in a trade or business in the United States, and if interest on a note or gain from a disposition of a note is effectively connected with the conduct of that trade or business and, in the case of an applicable tax treaty, is attributable to a permanent establishment or fixed base you maintain in the United States, you will be subject to regular U.S. federal income tax on the interest or gain in the same manner as if you were a U.S. person. If interest received with respect to the notes is taxable in that manner, it may be exempt from withholding tax. In order to establish such an exemption from U.S. withholding tax, you may provide to us, our payment agent or the person who would otherwise be required to withhold U.S. federal income tax, a properly completed and executed IRS Form W-8ECI or applicable substitute form. In addition to regular U.S. federal income tax, if you are a corporation, you may be subject to a U.S. branch profits tax.

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Sale, Exchange, and Other Disposition of the Notes

You generally will not be subject to U.S. federal income tax or withholding tax with respect to gain recognized on a sale, exchange, retirement or other taxable disposition of a note unless:

• the gain is effectively connected with your conduct of a trade or business within the United States, and, in the case of an applicable tax treaty, is attributable to a permanent establishment or fixed base you maintain in the United States; or

• if you are an individual, you are present in the United States for 183 or more days in the taxable year of the disposition and certain other requirements are met.

Information Reporting and Backup Withholding

Payments to you of interest on a note, and amounts withheld from such payments, if any, generally will be required to be reported to the IRS and to you. United States backup withholding tax generally will not apply to payments of interest and principal on a note to you if the statement described in “Non-U.S. Holders—Payments of Interest” is duly provided by you or you otherwise establish an exemption, provided that we do not have actual knowledge or reason to know that you are a U.S. person.

The payments of the proceeds of the disposition of notes to or through the U.S. office of a broker will be subject to information reporting and backup withholding unless you properly certify under penalties of perjury as to your non-U.S. status and specific other conditions are met or you otherwise establish an exemption. The proceeds of a disposition effected outside the United States by you of notes to or through a foreign office of a broker generally will not be subject to backup withholding or information reporting. However, if that broker is a U.S. person, a controlled foreign corporation for U.S. tax purposes, a foreign person 50% or more of whose gross income from all sources for certain periods is effectively connected with a trade or business in the United States, or a foreign partnership that is engaged in the conduct of a trade or business in the United States or that has one or more partners that are U.S. persons who in the aggregate hold more than 50% of the income or capital interests in the partnership, information reporting requirements will apply unless that broker has documentary evidence in its files of your non-U.S. status and has no actual knowledge to the contrary or unless you otherwise establish an exemption.

You are urged to consult your tax advisors regarding the application of information reporting and backup withholding to your particular situation, the availability of an exemption therefrom, and the procedure for obtaining such an exemption, if available. Any amounts withheld from a payment to you under the backup withholding rules will be allowed as a credit against your U.S. federal income tax liability and may entitle you to a refund, provided you timely furnish the required information to the IRS.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of notes received in exchange for initial notes where such initial notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for not less than 90 days after the consummation of the exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until [                    ], all dealers effecting transactions in the notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of notes by broker-dealers. Notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such notes. Any broker-dealer that resells notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The enclosed letter of transmittal states that, by acknowledging that it will deliver and be delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 90 days after the consummation of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the reasonable expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

Following completion of the exchange offer, we may, in our sole discretion, commence one or more additional exchange offers to holders of initial notes who did not exchange their initial notes for notes in the exchange offer on terms which may differ from those contained in this prospectus and the enclosed letter of transmittal. This prospectus, as it may be amended or supplemented from time to time, may be used by us in connection with any additional exchange offers. These additional exchange offers may take place from time to time until all outstanding initial notes have been exchanged for notes, subject to the terms and conditions in the prospectus and letter of transmittal distributed by us in connection with these additional exchange offers.

155

LEGAL MATTERS

The validity of the issuance of the notes covered by this prospectus will be passed upon for us by Andrews Kurth LLP, Houston, Texas.

EXPERTS

The financial statements of Sabine Pass LNG, L.P. as of and for the years ended December 31, 2006 and 2005, and for the period from October 20, 2003 (inception) to December 31, 2006 included in this prospectus, have been audited by UHY LLP, an independent registered public accounting firm, as set forth in their report thereon included therein. Such financial statements are included in this prospectus upon such report given on the authority of such firm as experts in accounting and auditing.

The board of directors of our general partner has engaged Ernst & Young LLP to serve as our independent auditor, effective as of March 1, 2007, for the fiscal year ending December 31, 2007. As a result, UHY LLP was dismissed as our independent auditor effective as of March 1, 2007. There have been no disagreements between us and UHY LLP on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure for the two fiscal years ended December 31, 2006 or for the period from January 1, 2007 through March 1, 2007. UHY LLP’s audit reports on our balance sheet as of December 31, 2006 and on our financial statements for the two years ended December 31, 2006 did not contain an adverse opinion or a disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles. For the two fiscal years ended December 31, 2006 and for the period from January 1, 2007 through March 1, 2007, we have not consulted with Ernst & Young LLP regarding the application of accounting principles to a specific transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements, nor did Ernst & Young LLP provide advice to us, either written or oral, that was an important factor considered by us in reaching a decision as to an accounting, auditing or financial reporting issue. Further, during the two fiscal years ended December 31, 2006 and for the period from January 1, 2007 through March 1, 2007, we have not consulted with Ernst & Young LLP on any matter that was the subject of a disagreement or a reportable event.

INDEPENDENT ENGINEER

Stone & Webster Management Consultants Inc. has prepared the Independent Engineer’s report that is included as Appendix A to this prospectus. The Independent Engineer’s report should be read in its entirety for complete information with respect to the subjects and issues discussed therein. As stated in the Independent Engineer’s report, the Independent Engineer has made a number of assumptions in reaching its conclusions, which are set forth therein, and has used the sources of information described therein. The Independent Engineer believes that the use of such information and assumptions is reasonable for the purposes of the Independent Engineer’s report. The Independent Engineer’s report has been included in this prospectus in reliance upon the conclusions therein and upon the Independent Engineer’s experience in the review of the design, development, construction and operation of projects similar to our LNG receiving terminal.

AVAILABLE INFORMATION

In connection with the commencement of the exchange offer, we will initially be subject to the reporting requirements of the Exchange Act and file with the SEC the annual reports, quarterly reports and other documents required to be filed under the Exchange Act. We will also provide copies of such reports or other documents to the trustee for forwarding to the holders of the notes as described in “Description of Notes—Reports.”

156

Any materials filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. We expect that any materials filed by us with the SEC will be filed electronically.

FORWARD-LOOKING STATEMENTS

This prospectus contains certain statements that are, or may be deemed to be, forward-looking statements. All statements, other than statements of historical fact, included herein are forward-looking statements. Included among forward-looking statements are, among others:

• statements that we expect to commence or complete construction of our LNG receiving terminal, or any expansions thereof, by certain dates, or at all;

• statements regarding future levels of domestic natural gas production, supply or consumption; future levels of LNG imports into North America; sales of natural gas in North America; and the transportation, other infrastructure or prices related to natural gas, LNG or other energy sources or hydrocarbon products;

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

• statements relating to the construction of our LNG receiving terminal, including statements concerning the engagement of any EPC or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;

• statements regarding any TUA or other agreement to be entered into or performed substantially in the future, including any cash distributions and revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification capacity that are, or may become subject to, TUAs or other contracts;

• statements that our LNG receiving terminal and any pipelines, when completed, will have certain characteristics, including amounts of regasification and storage capacities, a number of storage tanks and docks, pipeline deliverability and the number of pipeline interconnections, if any;

• statements regarding counterparties to our TUAs, construction contracts and other contracts;

• statements regarding our business strategy, our 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 assumptions, estimates, projections or conclusions;

• 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 do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this 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

157

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.

PRESENTATION OF INFORMATION

In this prospectus, we rely on and refer to information and statistics regarding our industry. We obtained this market data from independent industry publications or other publicly available information.

In this prospectus, unless the context otherwise requires:

• Bcf means billion cubic feet;

• Bcf/d means billion cubic feet per day;

• EPC means engineering, procurement and construction;

• EPCM means engineering, procurement, construction and management;

• LNG means liquefied natural gas;

• Mcf means thousand cubic feet;

• MMcf/d means million cubic feet per day;

• MMBtu means million British thermal units; and

• TUA means terminal use agreement.

158

INDEX TOFINANCIAL STATEMENTS

	Page
AUDITED FINANCIAL STATEMENTS OF SABINE PASS LNG, L.P.:
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2006 and 2005	F-3
Statements of Operations for the years ended December 31, 2006, 2005 and 2004, and the period from October 20, 2003 (date of inception) to December 31, 2006	F-4
Statements of Partners’ Capital (Deficit) at December 31, 2004, 2005 and 2006	F-5
Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004 and the period from October 20, 2003 (date of inception) to December 31, 2006	F-6
Notes to Financial Statements	F-7
UNAUDITED FINANCIAL STATEMENTS OF SABINE PASS LNG, L.P.:
Balance Sheets as of March 31, 2007 and December 31, 2006	F-21
Statements of Operations for the three months ended March 31, 2007 and 2006, and the period from October 20, 2003 (date of inception) to March 31, 2007	F-22
Statements of Partners’ Capital (Deficit) from the period of October 20, 2003 (date of inception) to March 31, 2007	F-23
Statements of Cash Flows for the three months ended March 31, 2007 and 2006 and the period from October 20, 2003 (date of inception) to March 31, 2007	F-24
Notes to Financial Statements	F-25

F-1

Report of Independent Registered Public Accounting Firm

To the Partners of

Sabine Pass LNG, L.P.:

We have audited the accompanying balance sheets of Sabine Pass LNG, L.P. (a development stage limited partnership, the “Partnership”) as of December 31, 2006 and 2005, and the related statements of operations, partners’ capital (deficit) and cash flows for each of the three years in the period ended December 31, 2006, and for the periods from October 20, 2003 (date of inception) to December 31, 2006. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Sabine Pass LNG, L.P. as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, and for the periods from October 20, 2003 (date of inception) to December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

February 9, 2007

F-2

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

BALANCE SHEETS

(in thousands)

	December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Restricted cash and cash equivalents	$	176,324		$	8,871
Interest receivable		5,226			5
Advance to EPC contactor		—			8,087
Advances to affiliate		379			242
Short-term unrealized derivative asset		—			423
Prepaid expenses		389			416
TOTAL CURRENT ASSETS		182,318			18,044
NON-CURRENT RESTRICTED CASH AND CASH EQUIVALENTS		982,613			—
PROPERTY, PLANT AND EQUIPMENT, NET		651,676			270,740
DEBT ISSUANCE COSTS, NET		33,970			18,497
ADVANCES UNDER LONG-TERM CONTRACTS		7,250			—
LNG INTANGIBLE ASSETS		18			17
LONG-TERM DERIVATIVE ASSETS		—			1,837
OTHER		266			—
TOTAL ASSETS	$	1,858,111		$	309,135
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES
Accounts payable	$	758		$	—
Accounts payable—affiliate		224		$	—
Accrued liabilities		36,670			44,403
Accrued liabilities—affiliate		652			435
TOTAL CURRENT LIABILITIES		38,304			44,838
LONG-TERM DEBT		2,032,000			—
DEFERRED REVENUE		40,000			40,000
LONG-TERM DEBT—AFFILIATE		—			37,377
INTEREST PAYABLE—AFFILIATE		—			120
OTHER		1,149			—
COMMITMENTS AND CONTINGENCIES		—			—
PARTNERS’ CAPITAL (DEFICIT)
Partners’ capital (deficit), including deficit accumulated during development stage of $72,432 and $11,672 at December 31, 2006 and 2005, respectively		(253,342	)		184,986
Accumulated other comprehensive income		—			1,814
TOTAL PARTNERS’ CAPITAL (DEFICIT)		(253,342	)		186,800
TOTAL LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)	$	1,858,111		$	309,135

See accompanying notes to financial statements.

F-3

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

STATEMENTS OF OPERATIONS

(in thousands)

	Year Ended December 31,									Period from October 20, 2003 (Date of Inception) to December 31, 2006
	2006			2005			2004
REVENUES	$	—		$	—		$	—		$	—
EXPENSES
Legal		2			203			1,434			2,227
Professional		571			281			568			1,571
Technical consulting		27			—			2,579			4,577
Land site rental		1,515			—			—			1,515
Depreciation expense		50			13			—			63
Overhead charge from affiliates		3,450			4,094			—			7,544
Phase 2 development reimbursement to affiliate		4,527			—			—			4,527
Other		123			120			101			397
TOTAL EXPENSES		10,265			4,711			4,682			22,421
LOSS FROM OPERATIONS		(10,265	)		(4,711	)		(4,682	)		(22,421	)
OTHER INCOME (EXPENSE)
Interest income		9,306			113			28			9,447
Interest expense		(15,463	)		—			—			(15,463	)
Loss on early extinguishment of debt		(23,761	)		—			—			(23,761	)
Derivative gain (loss), net		(20,577	)		343			—			(20,234	)
TOTAL OTHER INCOME (EXPENSE)		(50,495	)		456			28			(50,011	)
NET LOSS	$	(60,760	)	$	(4,255	)	$	(4,654	)	$	(72,432	)

See accompanying notes to financial statements.

F-4

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

STATEMENTS OF PARTNERS’ CAPITAL (DEFICIT)

(in thousands)

	General Partner		Limited Partner			Accumulated Other Comprehensive Income			Total Partners’ Capital (Deficit)
	Sabine Pass LNG-GP, Inc.		Sabine Pass LNG-LP, LLC
Balance at December 31, 2003		—		(2,763	)		—			(2,763	)
Distributions		—		(10,000	)		—			(10,000	)
Comprehensive loss:
Net loss		—		(4,654	)		—			(4,654	)
Total comprehensive loss										(4,654	)
Balance at December 31, 2004		—		(17,417	)		—			(17,417	)
Capital contributions		—		196,658			—			196,658
Rescinded distribution		—		10,000			—			10,000
Comprehensive loss:
Change in fair value of derivative instrument		—		—			1,814			1,814
Net loss		—		(4,255	)		—			(4,255	)
Total comprehensive loss										(2,441	)
Balance at December 31, 2005		—		184,986			1,814			186,800
Capital contributions		—		780			—			780
Distributions		—		(378,348	)		—			(378,348	)
Comprehensive loss:
Change in fair value of derivative instrument		—		—			(1,814	)		(1,814	)
Net loss		—		(60,760	)		—			(60,760	)
Total comprehensive loss										(62,574	)
Balance at December 31, 2006	$	—	$	(253,342	)	$	—		$	(253,342	)

See accompanying notes to financial statements.

F-5

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,									Period from October 20, 2003 (Date of Inception) to December 31, 2006
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(60,760	)	$	(4,255	)	$	(4,654	)	$	(72,432	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation		50			13			—			63
Non-cash derivative (gain) loss		23			(362	)		—			(339	)
Amortization of debt issuance costs		695			—			—			695
Loss on early extinguishment of debt		23,750			—			—			23,750
Changes in operating assets and liabilities:
Interest receivable		(5,221	)		19			(23	)		(5,225	)
Accounts payable and accrued liabilities		12,399			191			1,315			13,905
Accounts payable and accrued liabilities—affiliate		97			555			—			652
Deferred revenue		—			18,000			22,000			40,000
Payable to affiliate		—			(7,418	)		4,554			—
Other		1,066			(416	)		—			650
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(27,901	)		6,327			23,192			1,719
CASH FLOWS FROM INVESTING ACTIVITIES
Investment in restricted cash and cash equivalents		(1,150,066	)		(8,871	)		—			(1,158,937	)
LNG terminal construction-in-progress		(387,724	)		(229,073	)		—			(624,884	)
Advances to EPC contractor, net of transfers to construction-in-progress		—			(8,087	)		—			—
Advances to affiliate		(137	)		(242	)		—			(379	)
Other assets		(6,481	)		(64	)		(124	)		(6,769	)
NET CASH USED IN INVESTING ACTIVITIES		(1,544,408	)		(246,337	)		(124	)		(1,790,969	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of senior notes		2,032,000			—			—			2,032,000
Debt issuance costs		(43,966	)		(15,847	)		(1,246	)		(61,060	)
Proceeds from subordinated note—affiliate		—			37,377			—			37,377
Repayment of subordinated note—affiliate		(37,377	)		—			—			(37,377	)
Borrowings from credit facility		383,400			—			—			383,400
Repayment of credit facility		(383,400	)		—			—			(383,400	)
Distribution to limited partner		(378,348	)		—			—			(378,348	)
Limited partner contributions		—			196,658			—			196,658
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		1,572,309			218,188			(1,246	)		1,789,250
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		—			(21,822	)		21,822			—
CASH AND CASH EQUIVALENTS—beginning of year		—			21,822			—			—
CASH AND CASH EQUIVALENTS—end of year	$	—		$	—		$	21,822		$	—

See accompanying notes to financial statements.

F-6

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

NOTE 1—NATURE OF OPERATIONS

Sabine Pass LNG, L.P., a Delaware limited partnership, is a Houston-based partnership formed with one general partner, Sabine Pass LNG-GP, Inc. (“Sabine Pass GP”), a Cheniere Energy, Inc. (“Cheniere”) indirect, subsidiary, and one limited partner, Sabine Pass LNG-LP, LLC (“Sabine Pass LNG-LP”), which owns 100% of the Partnership and is an indirect subsidiary of Cheniere. Cheniere has a 91.8% ownership interest in Cheniere Energy Partners, L.P., which is the indirect parent of Sabine Pass GP, Sabine Pass LNG-LP and the Partnership. As used in these Notes to Financial Statements, the terms “we”, “us” and “our” refer to Sabine Pass LNG, L.P. We are in the development stage, and the purpose of this limited partnership is to own, develop and operate a liquefied natural gas (“LNG”) receiving and regasification terminal in western Cameron Parish, Louisiana on the Sabine Pass Channel (the “LNG receiving terminal”). After construction is completed, we will own and operate the LNG receiving terminal.

NOTE 2—DEVELOPMENT STAGE OPERATIONS

We were formed on October 20, 2003. Operations to date have been devoted to pre-construction and construction activities. Our ultimate profitability will depend on, among other factors, the successful completion of construction of our LNG receiving terminal and commencement of commercial operation, which is not expected until the second quarter of 2008 at the earliest.

NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Financial Statements include the accounts of Sabine Pass LNG, L.P. prepared in conformity with accounting principles generally accepted in the United States of America.

Use of Estimates

The preparation of our Financial Statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts in our Financial Statements and accompanying Notes to Financial Statements. Actual results could differ from those estimates and assumptions.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

LNG Site Related Costs

LNG site related costs include costs related to options to lease land that is used for our LNG receiving terminal. Such costs are capitalized and are amortized on a straight-line basis over their estimated useful lives.

Land Site Rentals

From inception to December 31, 2005, rental costs associated with ground or building operating leases that were incurred during the construction period were capitalized as part of LNG terminal construction-in-progress.

F-7

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

However, beginning January 1, 2006, these rental costs will be expensed in accordance with Financial Accounting Standard Board (“FASB”) issued FASB Staff Position (“FSP”) 13-1,Accounting for Rental Costs Incurred During a Construction Period, which is discussed below.

LNG Intangible Assets

LNG intangible assets include the costs of certain permits for our LNG receiving terminal. Amortization will begin when the Facility is operational and will be calculated on the straight-line method over the estimated useful life of the Facility.

Debt Issuance Costs

Debt issuance costs consist primarily of fees incurred directly related to the issuance of the Senior Notes (see Note 11). These costs are capitalized and are amortized to interest expense over the terms of the Senior Notes.

Revenue Recognition

LNG regasification capacity fees are recognized as revenue over the term of the respective terminal use agreements (“TUAs”). Advance capacity reservation fees are initially deferred. For a discussion of potential revenue from related parties, please read Note 13.

Income Taxes

We are not subject to either federal or state income taxes, as the partners are taxed individually on their proportionate share of our earnings. Accordingly, no provision or liability for federal or state income taxes is included in the accompanying Financial Statements.

Pursuant to the indenture entered into in connection with the issuance of the Senior Notes (as defined in Note 4), we are permitted to make distributions (“Tax Distributions”) for any fiscal year or portion thereof in which we are a limited partnership, disregarded entity or other substantially similar pass-through entity for federal or state income tax purposes. The permitted Tax Distributions are equal to the tax that we would owe if we were a corporation subject to federal and state income tax that filed separate federal and state income tax returns, excluding the amounts covered by the State Tax Sharing Agreement discussed immediately below. The Tax Distributions are limited to the amount of federal and/or state income taxes paid by Cheniere to the appropriate taxing authorities and are payable by us within 30 days of the date that Cheniere is required to make federal or state income tax payments to the appropriate taxing authorities.

In November 2006, we entered into a state franchise tax sharing agreement (the “State Tax Sharing Agreement”) with Cheniere pursuant to which Cheniere has agreed to prepare and file all Texas franchise tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined tax liability. If Cheniere, in its sole discretion, demands payment, then we will pay to Cheniere an amount equal to the Texas franchise tax that we would be required to pay if our Texas franchise tax liability were computed on a separate company basis. The State Tax Sharing Agreement contains similar provisions for other state and local taxes required to be filed by Cheniere and us on a combined, consolidated or unitary basis. The State Tax Sharing Agreement is effective for tax returns first due on or after January 1, 2008.

F-8

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

Concentration of Credit Risk

Financial instruments that potentially subject us to concentration of credit risk consist principally of restricted cash and cash equivalents. We maintain cash balances at financial institutions which may at times be in excess of federally insured levels. We have not incurred losses related to these balances to date.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction activities, major renewals and betterments are capitalized, while expenditures for maintenance and repairs are charged to expense as incurred. Interest costs incurred on debt obtained for the construction of property, plant and equipment are capitalized as construction-in-progress over the construction period or related debt, whichever is shorter. Once placed into service, the LNG receiving terminal construction costs will be depreciated using the straight-line depreciation method. Depreciation of computer and office equipment, computer software, leasehold improvements and vehicles is computed using the straight-line method over the estimated useful lives of the assets, which range from two to ten years. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses are recorded in operations.

In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144,Accounting for the Impairment or Disposal of Long-lived Assets, management periodically reviews for impairment of property, plant and equipment, whenever events or changes in circumstances have indicated that the carry amount of property, plant and equipment might not be recoverable. No such impairment was recorded for the years ended December 31, 2006 or 2005.

Derivative Instruments and Hedging Activities

We have used, and may in the future use, derivative instruments to limit our exposure to variability in expected future cash flows. We account for derivative instruments in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”). The statement established accounting and reporting standards requiring every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded on the balance sheet as either an asset or liability measured at fair value. SFAS No. 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met wherein gains and losses are reflected in partners’ capital as accumulated other comprehensive income (loss) (“AOCI”) until the hedged item is recognized. Hedge accounting allows a derivative’s gains and losses to offset related results on the hedged item on the statements of operations, and requires that we formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Only derivative instruments that are expected to be highly effective in offsetting anticipated gains or losses on the hedged cash flows and that are subsequently documented to have been highly effective can qualify for hedge accounting. Any ineffectiveness in hedging instruments whereby gains or losses do not exactly offset anticipated gains or losses of hedged cash flows is recorded in earnings in the period in which the gain or loss occurs.

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

F-9

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

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 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 believe that the adoption of SFAS No. 156 will not have a material impact on our financial position, results of operations or cash flows.

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 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 believe that the adoption of SFAS No. 157 will not have a material impact on our financial position, results of operations or cash flows.

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 in which the changes occur. SFAS No. 158 is effective for fiscal years ending after December 15, 2006. We

F-10

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

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.

NOTE 4—RESTRICTED CASH AND CASH EQUIVALENTS

In November 2006, we consummated a private offering of an aggregate principle amount of $2.0 billion of senior secured notes consisting of $550 million of 7 ¹/4% Senior Secured Notes due 2013 (the “2013 Notes”) and $1.5 billion of 7 ¹/2% Senior Secured Notes due 2016 (the “2016 Notes” and collectively with the 2013 Notes, the “Senior Notes”) (see Note 11). Under the terms of the Senior Notes, we were required to fund cash reserve accounts for approximately $335 million related to future interest payments through May 2009 and approximately $887 million to pay the remaining costs to complete Phase 1 and Phase 2 – Stage 1 of our LNG receiving terminal. These cash accounts are controlled by a collateral agent, and therefore, are shown as restricted cash and cash equivalents on the accompanying Balance Sheet. As of December 31, 2006, $176.3 million related to future interest payments due within one year and accrued construction costs have been classified as a current asset, and $982.6 million related to remaining construction costs and future interest payments due beyond one year have been classified as a non-current asset on the accompanying Balance Sheet.

At December 31, 2005, we had a restricted cash and cash equivalents balance of $8.9 million, classified as a current asset, under the terms of an amended and restated credit facility, which was subsequently terminated using a portion of the proceeds from the issuance of the Senior Notes in November 2006.

NOTE 5—ADVANCES TO EPC CONTRACTOR

In December 2004, we entered into an engineering, procurement and construction (“EPC”) contract with Bechtel to construct Phase 1 of our LNG receiving terminal. Under the EPC contract, we were required to make a 5% advance payment to Bechtel upon issuance of the final notice to proceed (“NTP”) related to the construction of Phase 1. A payment of $32.3 million was made to Bechtel in March 2005 when the NTP was issued and that amount was classified as a current asset. In accordance with the payment schedule included in the EPC contract, $2.7 million per month was being reclassified to construction-in-progress over a twelve-month period. As of December 31, 2006 and 2005, the remaining balance of the advance was zero and $8.1 million, respectively.

F-11

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

NOTE 6—PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is comprised of LNG terminal construction-in-progress expenditures, LNG site and related costs and fixed assets, as follows:

	December 31,
	2006			2005
LNG TERMINAL COSTS
LNG terminal construction-in-progress	$	651,369		$	270,489
LNG site and related costs, net		197			204
Total LNG terminal costs		651,566			270,693
FIXED ASSETS
Computer and office equipment		31			4
Computer software		33			20
Leasehold improvements		10			10
Vehicles		99			26
Accumulated depreciation		(63	)		(13	)
Total fixed assets, net		110			47
PROPERTY, PLANT AND EQUIPMENT, NET	$	651,676		$	270,740

Once our LNG receiving terminal is placed into service, the LNG terminal construction-in-progress costs will be depreciated using the straight-line depreciation method. We are in the process of determining the most appropriate approach in grouping identifiable components with similar estimated useful lives. Estimated useful lives for components, once construction is completed, are currently estimated to range between 10 and 50 years.

In February 2005 and July 2006, Phase 1 and Phase 2 – Stage 1, respectively, of our LNG receiving terminal satisfied the criteria for capitalization. Accordingly, costs associated with the construction of Phase 1 and Phase 2 – Stage 1 of our LNG receiving terminal have been capitalized as construction-in-progress since those times. During the year ended December 31, 2006 and 2005, we capitalized $22.3 million and $5.3 million, respectively, of interest expense, which consisted of interest expense qualifying to be capitalized, amortization of debt issuance costs and commitment fees under the Credit Facility and the Senior Notes during 2006 and only the Credit Facility in 2005.

NOTE 7—DEBT ISSUANCE COSTS

As of December 31, 2005, we had capitalized $18.5 million (net of accumulated amortization of $1.7 million), of costs directly associated with the arrangement of the credit facility. The debt issuance costs were amortized over a period of ten years, which was the term of the credit facility. Although there were no borrowings outstanding as of December 31, 2005, the amortization of the debt issuance cost was recorded to interest expense and subsequently capitalized as construction-in-progress during the construction period of our LNG receiving terminal. For the years ended December 31, 2005, the amount amortized and capitalized was $1.7 million.

When we amended the credit facility in July 2006, we incurred additional debt issuance costs of $9.1 million that were capitalized. These costs, along with the debt issuance costs capitalized as part of the original credit facility, were amortized using straight-line amortization through July 1, 2015.

F-12

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

In November 2006, we paid off and terminated the Credit Facility using a portion of the borrowings from the proceeds received from the issuance of the Senior Notes. As a result of the early termination of the Credit Facility, we were required to immediately expense the related unamortized debt issuance costs. For the year ended December 31, 2006, we had expensed debt issuance costs of $23.8 million, which is presented in the Statements of Operations as a Loss on early extinguishment of debt.

As of December 31, 2006, we had capitalized $34.6 million of costs directly associated with the Senior Notes offering consummated in November 2006, net of accumulated amortization, as follows (in thousands):

Long-term Debt	Debt Issuance Costs		Amortization Period	Accumulated Amortization			Net Costs
2013 Notes	$	9,361	7 years	$	(212	)	$	9,149
2016 Notes		25,223	10 years		(402	)		24,821
	$	34,584		$	(614	)	$	33,970

Scheduled amortization of the debt issuance costs related to the Senior Notes for the next five years is estimated to be $19.3 million.

NOTE 8—DERIVATIVE INSTRUMENTS

Interest Rate Derivative Instruments

In connection with the closing of the original credit facility in February 2005, we entered into swap agreements (“Sabine Swaps”) with HSBC Bank, USA and Société Générale. Under the terms of the Sabine Swaps, we were able to hedge against rising interest rates, to a certain extent, with respect to our drawings under the Credit Facility, up to a maximum amount of $700 million. The Sabine Swaps had the effect of fixing the LIBOR component of the interest rate payable under the original credit facility with respect to hedged drawings under the original credit facility up to a maximum of $700 million at 4.49% from July 25, 2005 through March 25, 2009 and at 4.98% from March 26, 2009 through March 25, 2012. The final termination date of the Sabine Swaps was March 25, 2012.

In connection with the closing of the Amended Credit Facility in July 2006, we entered into additional interest rate swap agreements with HSBC Bank, USA and Société Générale (the “Amended Sabine Swaps” and collectively with the Sabine Swaps, the “Swaps”). The Swaps had the combined effect of fixing the LIBOR component of the interest rate payable on borrowings under the amended Credit Facility up to a maximum of $1.25 billion at a blended rate of 5.26% from July 25, 2006 through July 1, 2015.

In conjunction with the termination of the amended Credit Facility in November 2006, we terminated the Swaps and recognized a loss $20.6 million. In accordance with EITF 00-9,Classification of a Gain or Loss from a Hedge of Debt That Is Extinguished, the loss recognized as a result of early settlement the Sabine Swaps is presented on the Statements of Operations as a Derivative loss.

Accounting for Hedges

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (“SFAS No. 133”)and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments. Under SFAS No. 133, we are required to record derivatives on our Balance Sheets as

F-13

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

either an asset or liability measured at their fair value, unless exempted from derivative treatment under the normal purchase and normal sale exception. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met. These criteria require that the derivative is determined to be effective as a hedge and that it is formally documented and designated as a hedge.

We determined that the Swaps qualified as cash flow hedges within the meaning of SFAS No. 133 and designated them as such. We assessed both at the inception of each of the Swaps and on an on-going basis, whether the Swaps that were used in our hedging transactions were highly effective in offsetting changes in cash flows of the hedged items. At inception, we determined the hedging relationship of the Swaps and the underlying debt to be highly effective. On an on-going basis we monitored the actual dollar offset of the Swaps’ market values as compared to hypothetical cash flow hedges. Any ineffective portion of the cash flow hedges will be reflected in earnings. Ineffectiveness is the amount of gains or losses from derivative instruments that are not offset by corresponding and opposite gains or losses on the expected future transaction. We continued to assess the hedge effectiveness of the Swaps on a quarterly basis in accordance with the provisions of SFAS No. 133 until they were terminated in November 2006.

SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income (“OCI”) and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. In our case, the impact on earnings was a reduction of interest expense of $1.0 million and zero for the years ended December 31, 2006 and 2005, respectively. If the forecasted transaction is no longer probable of occurring, the associated gain or loss recorded in OCI is recognized currently in earnings.

NOTE 9—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in thousands):

	December 31,
	2006		2005
Interest and related debt fees	$	21,815	$	4,640
LNG terminal construction costs		13,899		39,730
Affiliate		652		435
Other		956		33
	$	37,322	$	44,838

NOTE 10—DEFERRED REVENUES

In November 2004, Total LNG USA, Inc. (“Total”) paid us a nonrefundable advance capacity reservation fee of $10.0 million in connection with the reservation of approximately 1.0 Bcf/d of LNG regasification capacity at our LNG receiving terminal. An additional advance capacity reservation fee payment of $10.0 million was paid by Total to us in April 2005. The advance capacity reservation fee payments will be amortized over a 10-year period after operations commence as a reduction of Total’s regasification capacity fee under its TUA. As a result, we recorded the advance capacity reservation fee payments that we received, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

In November 2004, we also entered into a TUA to provide Chevron USA, Inc. (“Chevron”), with approximately 700 MMcf/d of LNG regasification capacity at our LNG receiving terminal. In December 2005,

F-14

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

Chevron exercised its option to increase its reserved capacity by approximately 300 MMcf/d to approximately 1.0 Bcf/d and paid us an additional $3.0 million advance terminal capacity reservation fee. As of December 31, 2005, Chevron had made advance terminal capacity reservation fee payments to us totaling $20.0 million, with $12.0 million paid in 2004 and $8.0 million paid in 2005. These advance terminal capacity reservation fee payments will be amortized over a 10-year period as a reduction of Chevron’s regasification capacity fee under the TUA. As a result, we recorded the advance capacity reservation fee payments that we received, although non-refundable, as deferred revenue to be amortized to income over the corresponding 10-year period.

As of December 31, 2006 and 2005, we had recorded $40.0 million as deferred revenue related to advance capacity reservation fee payments.

NOTE 11—LONG-TERM DEBT

As of December 31, 2006 and 2005, our long-term debt was comprised of the following (in thousands):

	December 31,
	2006		2005
Senior Notes	$	2,032,000	$	—
Subordinated Promissory Note—Affiliate		—		37,377
	$	2,032,000	$	37,377

Senior Secured Notes

In November 2006, we consummated a private offering of Senior Notes. The Senior Notes were offered to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), and in offshore transactions to non-United States persons in reliance on Regulation S under the Securities Act. At closing, net proceeds of approximately $2.0 billion, net of commissions, from the offering were used as follows: approximately $380.0 million to repay borrowings under, and replace, the Credit Facility; approximately $380.0 million was distributed to Sabine Pass LNG-LP; approximately $335.0 million was used to fund a reserve account for scheduled interest payments on the Senior Notes through May 2009; and approximately $18.0 million to terminate the Sabine Swaps and for other expenses. The remaining approximately $887.0 million of net proceeds from the offering will be used to fund the remaining costs to complete Phase 1 and Phase 2 – Stage 1 of the LNG receiving terminal.

We may redeem some or all of the Senior Notes at a redemption price equal to 100% of the principal amount plus a make-whole premium, plus accrued and unpaid interest and additional interest, if any, to the redemption date. Until November 30, 2009, we may redeem up to 35% of the aggregate principal amount of the 2013 Notes and up to 35% of the aggregate principal amount of the 2016 Notes with the net cash proceeds of one or more equity offerings by us with the proceeds that we retain or that are contributed to us, as applicable, at par plus a premium equal to the coupon, plus accrued and unpaid interest and additional interest, if any, as long as at least 65% of the aggregate principal amount of the 2013 Notes and the 2016 Notes, respectively, remains outstanding immediately after such optional redemption and such optional redemption occurs within 90 days of the date of the closing of such equity offering.

Under the indenture governing the Senior Notes, except for permitted tax distributions, we may not make distributions until certain conditions are satisfied. The indenture requires that we apply our net operating cash flow (i) first, to fund with monthly deposits our next semiannual payment of approximately $75.5 million of interest on the Senior Notes, and (ii) second, to fund a one-time, permanent debt service reserve fund equal to

F-15

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

one semiannual interest payment of approximately $75.5 million on the Senior Notes. Distributions will be permitted only after Phase 1 Target Completion, as defined in the indenture governing the Senior Notes, or such earlier date as project revenues are received, upon satisfaction of the foregoing funding requirements, after satisfying a fixed charge coverage ratio test of 2:1 and after satisfying other conditions specified in the indenture.

Credit Facility

In February 2005, we entered into the original credit facility, which was subsequently amended and restated in July 2006. The Amended Credit Facility increased the amount of the loans available to us from $822 million to $1.5 billion to finance a substantial majority of the costs of constructing and placing into operation Phase 1 and Phase 2 – Stage 1 of our LNG receiving terminal. In November 2006, as discussed above, borrowings under the Credit Facility were repaid, and the credit facility was terminated in conjunction with the issuance of the Senior Notes.

Borrowings under the credit facility bore interest at a variable rate equal to LIBOR plus the applicable margin. The applicable margin varied from 0.875% to 1.125% during the term of the Credit Facility. Interest was calculated on the unpaid principal amount outstanding and was payable semi-annually in arrears. A commitment fee of 0.50% per annum on the daily, undrawn portion of the lenders’ commitment was required. Administrative fees were also paid annually to the agent and the collateral agent.

Subordinated Promissory Note—Affiliate

In November 2005, to fund expenditures related to our LNG receiving terminal, we entered into a subordinated promissory note with an affiliate, Cheniere LNG Financial Services, Inc., that bore interest at LIBOR plus a 3.00% margin and terminated on June 30, 2015. As of December 31, 2005, the unpaid principal balance of the subordinated promissory note was $37.4 million. In July 2006, we repaid the subordinated promissory note and accrued interest payable to our affiliate with borrowings from the Credit Facility.

NOTE 12—FINANCIAL INSTRUMENTS

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported on the balance sheet for cash and cash equivalents, restricted cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to their short-term nature. We use available marketing data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107,Disclosures about Fair Value of Financial Instruments, and does not impact our financial position, results of operations of cash flows.

Long-Term Debt:

	December 31, 2006
	Carrying Amount		Estimated Fair Value
2013 Notes (1)	$	550,000	$	547,250
2016 Notes (1)		1,482,000	$	1,478,295
	$	2,032,000	$	2,025,545

(1) The fair value of the Senior Notes was based on quotations obtained from broker-dealers who made markets in these and similar instruments as of December 29, 2006.

F-16

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

NOTE 13—RELATED PARTY TRANSACTIONS

In August 2006, we reimbursed an affiliate for certain previously incurred costs directly related to Phase 2 – Stage 1 of our LNG receiving terminal. These costs, which amounted to $14.9 million, were reimbursed in connection with borrowings under the Credit Facility. We accounted for these reimbursed costs consistent with how the affiliated company recorded these costs, which was consistent with our accounting policy related to accounting for LNG activities. The reimbursed costs were recorded by us as a $4.5 million Phase 2 development reimbursement expense on the Statement of Operations, $6.4 million as an addition to LNG terminal construction-in-progress, $3.7 million as advances under long-term contracts and $0.3 million as debt issuance costs on the Balance Sheet. In addition to the August 2006 reimbursement, Sabine Pass LNG-LP contributed $0.8 million to us to fund additional Phase 2 – Stage 1 costs.

As of December 31, 2006 and 2005, we had $0.4 million and $0.2 million, respectively, of advances to affiliates.

During 2006 and 2005, we paid a combined management fee of $0.4 million per month as required under the O&M Agreement and the Sabine Pass LNG MSA (both described below under Note 14) totaling $5.2 million and $4.0 million, respectively. These costs are included as an overhead charge from affiliates, net of capitalized general and administrative costs, within the accompanying Statements of Operations. As of December 31, 2006 and 2005, we had $0.4 million and $0.4 million, respectively, of accrued liabilities to our affiliates related to such management fees.

NOTE 14—COMMITMENTS AND CONTINGENCIES

Lease Commitments

The following is a schedule by years of future minimum rental payments required as of December 31, 2006 under the LNG site leases described below (in thousands):

Year ending December 31:
2007	$	1,507
2008		1,506
2009		1,506
2010		1,501
2011		1,501
Later years (1)		124,583
Total minimum payments required	$	132,104

(1) The later years include the remaining initial term and the six 10-year extensions, as the lease option renewals were reasonably assured, as defined in SFAS No. 13,Accounting for Leases.

LNG Site Lease

In January 2005, we exercised our options and entered into three land leases for the site of our LNG receiving terminal. The leases have an initial term of 30 years, with options to renew for six 10-year extensions with similar terms as the initial term. In February 2005, two of the three leases were amended, thereby increasing the total acreage under lease to 853 acres and increasing the annual lease payments to $1.5 million. The annual

F-17

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

lease payment will be adjusted for inflation based on a consumer price index, as defined in the lease agreements, every five years. For 2005, these payments totaling $1.5 million were capitalized as part of the construction cost of our LNG receiving terminal; however, beginning in January 2006, these lease payments have been expensed as required by FSP FAS 13-1 and resulted in $1.5 million being recognized as land site rental expense on the Statements of Operations for 2006.

EPC Agreements

Phase 1 EPC Agreements

In December 2004, we entered into a lump-sum turnkey EPC agreement with Bechtel pursuant to which Bechtel is providing services for the engineering, procurement and construction of Phase 1 of our LNG receiving terminal. In December 2004, a limited notice to proceed (“NTP”) was issued and accepted by Bechtel, at which time Bechtel was required to promptly commence performance of certain off-site engineering and preparatory work under the EPC agreement. In early April 2005, a final NTP was issued, and Bechtel commenced all other aspects of work under the EPC agreement. We agreed to pay Bechtel a contract price of $646.9 million plus certain reimbursable costs. This contract price is subject to adjustment for changes in certain commodity prices, contingencies, change orders and other items. Payments under the EPC agreement will be made in accordance with the payment schedule set forth in the EPC agreement. The contract price and payment schedule, including milestones, may be amended only by change order. Bechtel will be liable to us for certain delays in achieving substantial completion, minimum acceptance criteria and performance guarantees. Bechtel will be entitled to a scheduled bonus of $12.0 million, or a lesser amount in certain cases, if on or before April 3, 2008, Bechtel completes construction sufficient to achieve, among other requirements specified in the EPC agreement, a sendout rate of at least 2.0 Bcf/d for a minimum sustained test period of 24 hours. Bechtel will be entitled to receive an additional bonus of up to $67,000 per day (up to a maximum of $6.0 million) for each day that commercial operation is achieved prior to April 1, 2008. As of February 14, 2007, change orders for $121.3 million had been approved, increasing the total contract price to $768.2 million.

Phase 2 – Stage 1 EPC Agreements

In July 2006, we entered into an engineering, procurement, construction and management (“EPCM”) agreement for Phase 2 – Stage 1 with Bechtel for engineering, procurement, construction and management of construction services in connection with the 1.4 Bcf/d expansion of our LNG receiving terminal. 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 the our sole discretion upon completion of Phase 2 – Stage 1.

In July 2006, we entered into an EPC LNG Unit Rate Soil Improvement Contract with Remedial Construction Services, L.P. (“Remedial”) for engineering, procurement, and construction of soil improvement work. Work includes, but is not limited to, design, surveying, estimating, procurement and transportation of materials, equipment, labor, supervision and construction activities necessary to satisfactorily complete work on the Phase 2 – Stage 1 site. The estimated total contract price is $28.5 million. A 10% initial payment of $2.9 million was made to Remedial in August 2006 and is classified under advances under long-term contracts on the Balance Sheets. Additional progress payments will be paid based on quantities of work performed at unit rates, minus 10% retainage that will be paid upon final completion as well as any credits and early payment discounts applicable.

In July 2006, we entered into an EPC LNG Tank Contract with Diamond LNG LLC (“Diamond”) and Zachry Construction Corporation (“Zachry” and collectively with Diamond, the “Tank Contractor”) for the

F-18

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

construction of two Phase 2 – Stage 1 LNG storage tanks. The estimated total contract price for the two Phase 2 –Stage 1 LNG storage tanks is $140.9 million. An initial payment of $6.4 million was made to Diamond and Zachry in August 2006. Additional milestone payments for work incurred, minus a 5% retainage that will be paid upon final completion, will be based on a lump-sum, fixed price, subject to adjustments based on fluctuations in the cost of labor and materials.

LNG Commitments

We have entered into TUAs with Total, Chevron and Cheniere Marketing, Inc., an affiliate and a wholly-owned subsidiary of Cheniere (“Cheniere Marketing”), to provide berthing for LNG tankers and for the unloading, storage and regasification of LNG at our LNG receiving terminal.

Service Agreements

Operation and Maintenance Agreement

In February 2005, we entered into an Operation and Maintenance Agreement (the “O&M Agreement”), with Cheniere LNG O&M Services, L.P. (“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 our LNG receiving terminal. The O&M Agreement will remain in effect until 20 years after substantial completion of our LNG receiving terminal. Prior to substantial completion of our LNG receiving terminal, we are 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 our LNG receiving terminal, 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 us and O&M Services at the beginning of each operating year. In addition, we are required to reimburse O&M Services for its maintenance capital expenditures and operating expenses, which consist of labor, maintenance, land lease and insurance expenses.

Management Services Agreement

In February 2005, we entered into a Management Services Agreement (the “Sabine Pass LNG MSA”) with Sabine Pass GP. Pursuant to the Sabine Pass LNG MSA, we appointed Sabine Pass GP to manage the construction and operation of our 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 our LNG receiving terminal, we are required to pay Sabine Pass GP a monthly fixed fee of $340,000 (indexed for inflation); thereafter, the monthly fixed fee will increase to $520,000 (indexed for inflation).

Other Commitments

Cheniere Marketing’s Option for a Sixth LNG Storage Tank

In November 2006, we entered into the Cheniere Marketing TUA to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at our LNG receiving terminal. Under the Cheniere Marketing TUA, Cheniere Marketing has the option to require us to construct a sixth LNG storage tank, which we may have to incur additional debt to construct. If Cheniere Marketing exercises its option, we will have to negotiate one or more new construction agreements with one or more new contractors.

F-19

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

NOTES TO FINANCIAL STATEMENTS—(Continued)

(Dollar amounts in tables, unless otherwise indicated, are in thousands)

State Tax Sharing Agreement

In November 2006, we entered into a State Tax Sharing Agreement with Cheniere pursuant to which Cheniere has agreed to prepare and file all Texas franchise tax returns which we and Cheniere are required to file on a combined basis and to timely pay the combined Texas franchise tax liability. If Cheniere, in its sole discretion, demands such payments, we will pay to Cheniere an amount equal to the Texas franchise tax that we would be required to pay if our Texas franchise tax liability were computed on a separate company basis. The State Tax Sharing Agreement contains similar provisions for other state and local taxes required to be filed by Cheniere and us on a combined, consolidated or unitary basis. The State Tax Sharing Agreement is effective for tax returns first due on or after January 1, 2008. As of December 31, 2006, we had made no payments to Cheniere under this State Tax Sharing Agreement.

Legal Proceedings

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, as of December 31, 2006 and 2005, there were no threatened or pending legal matters that would have a material impact on our results of operations, financial position or cash flows.

NOTE 15—SUPPLEMENTAL CASH FLOW INFORMATION AND DISCLOSURES OF NON-CASH TRANSACTIONS

The following table provides supplemental disclosure of cash flow information (in thousands):

	Year Ended December 31,							Period from October 20, 2003 (Date of Inception) to December 31, 2006
	2006		2005			2004
Cash paid for interest (1)	$	12,287	$	2,066		$	—	$	14,353
Non-Cash distribution payable	$	—	$	(10,000	)	$	10,000	$	—
Construction-in-progress and debt issuance additions funded with accrued liabilities	$	16,018	$	42,812		$	—	$	16,018

(1) All cash paid for interest was capitalized as construction-in-progress.

F-20

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE LIMITED PARTNERSHIP)

BALANCE SHEETS

(in thousands)

	March 31, 2007			December 31, 2006
	(unaudited)
ASSETS
CURRENT ASSETS
Restricted cash and cash equivalents	$	209,645		$	176,324
Interest receivable		4,901			5,226
Advances to affiliate		1,327			379
Prepaid expenses		380			389
TOTAL CURRENT ASSETS		216,253			182,318
NON-CURRENT RESTRICTED CASH AND CASH EQUIVALENTS		882,919			982,613
PROPERTY, PLANT AND EQUIPMENT, NET		769,436			651,676
DEBT ISSUANCE COSTS, NET		32,646			33,970
ADVANCES UNDER LONG-TERM CONTRACTS		14,022			7,250
LNG INTANGIBLE ASSETS		18			18
OTHER		193			266
TOTAL ASSETS	$	1,915,487		$	1,858,111
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES
Accounts payable	$	8,546		$	758
Accounts payable—affiliate		70			224
Accrued liabilities		99,534			36,670
Accrued liabilities—affiliate		435			652
TOTAL CURRENT LIABILITIES		108,585			38,304
LONG-TERM DEBT		2,032,000			2,032,000
DEFERRED REVENUE		40,000			40,000
OTHER NON-CURRENT LIABILITIES		1,154			1,149
COMMITMENTS AND CONTINGENCIES		—			—
PARTNERS’ CAPITAL (DEFICIT)
Partners’ deficit, including deficits accumulated during development stage of $85,342 and $72,432 at March 31, 2007 and December 31, 2006, respectively		(266,252	)		(253,342	)
TOTAL PARTNERS’ CAPITAL (DEFICIT)		(266,252	)		(253,342	)
TOTAL LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)	$	1,915,487		$	1,858,111

See accompanying notes to financial statements.

F-21

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE ENTERPRISE)

STATEMENTS OF OPERATIONS

(in thousands)

(unaudited)

	For the Three Months Ended March 31,						Period from October 20, 2003 (Date of Inception) to March 31, 2007
	2007			2006
REVENUES	$	—		$	—		$	—
EXPENSES
Legal		—			—			2,227
Professional		111			126			1,683
Technical consulting		—			—			4,577
Land site rental		401			382			1,916
Depreciation expense		20			10			83
Labor and overhead charge from affiliate		1,324			1,025			8,868
Phase 2–Stage 1 development reimbursement to affiliate		—			—			4,527
Other		4			47			400
TOTAL EXPENSES		1,860			1,590			24,281
LOSS FROM OPERATIONS		(1,860	)		(1,590	)		(24,281	)
OTHER INCOME (EXPENSE)
Interest income		14,767			49			24,214
Interest expense		(25,817	)		—			(41,280	)
Loss on early extinguishment of debt		—			—			(23,761	)
Derivative gain (loss), net		—			761			(20,234	)
TOTAL OTHER INCOME (EXPENSE)		(11,050	)		810			(61,061	)
NET LOSS	$	(12,910	)	$	(780	)	$	(85,342	)

See accompanying notes to financial statements.

F-22

SABINE PASS LNG, L.P.

(DEVELOPMENT STAGE ENTERPRISE)

STATEMENTS OF PARTNERS’ CAPITAL (DEFICIT)

(in thousands)

(unaudited)

	General Partner		Limited Partner			Accumulated Other Comprehensive Income			Total Partners’ Capital (Deficit)
	Sabine Pass LNG-GP, Inc.		Sabine Pass LNG-LP, LLC
Balance at October 20, 2003	$	—	$	—		$	—		$	—
Net loss		—		(2,763	)		—			(2,763	)
Balance at December 31, 2003		—		(2,763	)		—			(2,763	)
Distributions		—		(10,000	)		—			(10,000	)
Net loss		—		(4,654	)		—			(4,654	)
Balance at December 31, 2004		—		(17,417	)		—			(17,417	)
Capital contributions		—		196,658			—			196,658
Rescinded distribution		—		10,000			—			10,000
Change in fair value of derivative instrument		—		—			1,814			1,814
Net loss		—		(4,255	)		—			(4,255	)
Balance at December 31, 2005		—		184,986			1,814			186,800
Capital contributions		—		780			—			780
Distributions		—		(378,348	)		—			(378,348	)
Change in fair value of derivative instrument		—		—			(1,814	)		(1,814	)
Net loss		—		(60,760	)		—			(60,760	)
Balance at December 31, 2006		—		(253,342	)		—			(253,342	)
Net loss		—		(12,910	)		—			(12,910	)
Balance at March 31, 2007	$	—	$	(266,252	)	$	—		$	(266,252	)

See accompanying notes to financial statements.

F-23

SABINE PASS LNG, L.P.

A DEVELOPMENT STAGE ENTERPRISE

STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Three Months Ended March 31,						Period from October 20, 2003 (Date of Inception) to March 31, 2007
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(12,910	)	$	(780	)	$	(85,342	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation		20			10			83
Non-cash derivative gain		—			(676	)		—
Non-cash restricted interest income		(14,767	)		—			(23,831	)
Amortization of debt issuance costs		950			—			1,645
Loss on early extinguishment of debt		—			—			23,750
Changes in operating assets and liabilities:
Interest receivable		—			(1	)		—
Accounts payable and accrued liabilities		26,531			(877	)		40,520
Accounts payable and accrued liabilities—affiliate		(217	)		—			435
Deferred revenue		—			—			40,000
Payable to affiliate		70			—			70
Other		10			(895	)		231
NET CASH USED IN OPERATING ACTIVITIES		(313	)		(3,219	)		(2,439	)
CASH FLOWS FROM INVESTING ACTIVITIES
Use of (investment in) restricted cash and cash equivalents		81,465			8,500			(1,073,634	)
LNG terminal construction-in-progress		(73,015	)		(78,499	)		(697,899	)
Advances to EPC contractor, net of transfers to construction-in-progress		—			8,087			—
Advances under long-term contracts		(6,555	)		—			(13,317	)
Other		(948	)		(107	)		(1,327	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		947			(62,019	)		(1,786,177	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of senior notes		—			—			2,032,000
Debt issuance costs		(634	)		(4,762	)		(61,694	)
Proceeds from subordinated note—affiliate		—			—			37,377
Repayment of subordinated note—affiliate		—			—			(37,377	)
Borrowings from Sabine Pass credit facility		—			70,000			383,400
Repayment of Sabine Pass credit facility		—			—			(383,400	)
Distribution to partner		—			—			(378,348	)
Capital contributions by partner		—			—			196,658
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES		(634	)		65,238			1,788,616
NET INCREASE IN CASH AND CASH EQUIVALENTS		—			—			—
CASH AND CASH EQUIVALENTS—beginning of period		—			—			—
CASH AND CASH EQUIVALENTS—end of period	$	—		$	—		$	—

See accompanying notes to financial statements.

F-24

SABINE PASS LNG, L.P.

A DEVELOPMENT STAGE ENTERPRISE

NOTES TO FINANCIAL STATEMENTS

(unaudited)

NOTE 1—Nature of Operations and Basis of Presentation

Sabine Pass LNG, L.P., a Delaware limited partnership, is a Houston-based partnership formed with one general partner, Sabine Pass LNG-GP, Inc. (“Sabine Pass GP”) and one limited partner, Sabine Pass LNG-LP, LLC (“Sabine Pass LNG-LP”). As used in these Notes to Financial Statements, the terms “we”, “us” and “our” refer to Sabine Pass LNG, L.P. We are in the development stage, and the purpose of this limited partnership is to own, develop and operate a liquefied natural gas (“LNG”) receiving and regasification terminal in western Cameron Parish, Louisiana on the Sabine Pass Channel (the “LNG receiving terminal”). After construction is completed, we will own and operate the LNG receiving terminal.

The accompanying unaudited Financial Statements of Sabine Pass LNG, L.P. have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information and with Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In our opinion, all adjustments, consisting only of normal recurring adjustments necessary for a fair presentation, have been included.

The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Results of operations for the three months ended March 31, 2007 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2007.

New Accounting Pronouncements

In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 159,The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This statement is expected to expand the use of fair value measurement, which is consistent with the FASB’s long-term measurement objectives for accounting for financial instruments. This statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007, although earlier adoption is permitted. Management has not determined the effect that adopting this statement would have on our financial condition or results of operations.

NOTE 2—Development Stage Operations

We were formed on October 20, 2003. Operations to date have been devoted to pre-construction and construction activities. Our ultimate profitability will depend on, among other factors, the successful completion of construction of our LNG receiving terminal and commencement of commercial operation, which is not expected until the second quarter of 2008 at the earliest. As of March 31, 2007, we had a cumulative deficit of $85.3 million.

NOTE 3—Restricted Cash and Cash Equivalents

In November 2006, we consummated a private offering of an aggregate principle amount of $2.0 billion of senior secured notes consisting of $550 million of 7 ¹/4% Senior Secured Notes due 2013 (the “2013 Notes”) and

F-25

SABINE PASS LNG, L.P.

A DEVELOPMENT STAGE ENTERPRISE

NOTES TO FINANCIAL STATEMENTS—(Continued)

(unaudited)

$1.5 billion of 7 ¹/2% Senior Secured Notes due 2016 (the “2016 Notes” and, collectively with the 2013 Notes, the Senior Notes”) (see Note 6—Long-Term Debt). Under the terms and conditions of the Senior Notes, we were required to fund cash reserve accounts for approximately $335 million related to future interest payments through May 2009 and approximately $887 million to pay the remaining costs to complete the initial phase (“Phase 1”) and the first stage of the second phase (“Phase 2—Stage 1”) of the Sabine Pass LNG receiving terminal. These cash accounts are controlled by a collateral trustee, and therefore, are shown as Restricted Cash and Cash Equivalents on the accompanying Balance Sheets. As of March 31, 2007 and December 31, 2006, $209.6 million and $176.3 million, respectively, related to future interest payments due within one year and accrued construction costs have been classified as a current asset, and $882.9 million and $982.6 million, respectively, related to remaining construction costs and future interest payments due beyond one year have been classified as a non-current asset on the accompanying Balance Sheets.

NOTE 4—Property, Plant and Equipment

Property, plant and equipment is comprised of LNG terminal construction-in-progress expenditures, LNG site and related costs and fixed assets, as follows (in thousands):

	March 31, 2007			December 31, 2006
LNG TERMINAL COSTS
LNG terminal construction-in-progress	$	769,028		$	651,369
LNG site and related costs, net		196			197
Total LNG terminal costs		769,224			651,566
FIXED ASSETS
Computer and office equipment		85			31
Computer software		36			33
Leasehold improvements		10			10
Vehicles		164			99
Accumulated depreciation		(83	)		(63	)
Total fixed assets, net		212			110
PROPERTY, PLANT AND EQUIPMENT, NET	$	769,436		$	651,676

Once our LNG receiving terminal is placed into service, the LNG terminal construction-in-progress costs will be depreciated using the straight-line depreciation method. We are in the process of determining the most appropriate approach in grouping identifiable components with similar estimated useful lives. Estimated useful lives for components, once construction is completed, are currently estimated to range between 10 and 50 years.

In February 2005 and July 2006, Phase 1 and Phase 2—Stage 1, respectively, of our LNG receiving terminal satisfied the criteria for capitalization. Accordingly, costs associated with the construction of Phase 1 and Phase 2—Stage 1 of our LNG receiving terminal have been capitalized as construction-in-progress since those dates. During the three months ended March 31, 2007 and 2006, we capitalized $12.9 million and $2.8 million, respectively, of interest expense, which consisted primarily of interest expense qualifying to be capitalized, amortization of debt issuance costs and commitment fees under the Senior Notes during the three months ended March 31, 2007 and a credit facility during the three months ended March 31, 2006.

F-26

SABINE PASS LNG, L.P.

A DEVELOPMENT STAGE ENTERPRISE

NOTES TO FINANCIAL STATEMENTS—(Continued)

(unaudited)

NOTE 5—Accrued Liabilities

Accrued liabilities consisted of the following (in thousands):

	March 31, 2007		December 31, 2006
Interest and related debt fees	$	59,571	$	21,815
LNG terminal construction costs		39,873		13,899
Affiliate		435		652
Other		90		956
	$	99,969	$	37,322

NOTE 6—Long-Term Debt

As of March 31, 2007 and December 31, 2006, our long-term debt consisted of the following (in thousands):

	March 31, 2007		December 31, 2006
Senior Notes	$	2,032,000	$	2,032,000

Senior Notes

In November 2006, we consummated a private offering of an aggregate principal amount of $2,032 million of Senior Notes, consisting of $550 million of the 2013 notes and $1,482 million of the 2016 notes. We placed $335 million of the net proceeds in a reserve account to fund scheduled interest payments on the Senior 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 our 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 Senior Notes to repay indebtedness, to make a distribution to Cheniere LNG Holdings, LLC for the repayment of its outstanding term loan and to pay fees and expenses related to the issuance of the Senior Notes.

Interest on the Senior Notes is payable semi-annually in arrears on May 30 and November 30 of each year, beginning May 30, 2007. The Senior Notes are secured on a first-priority basis by a security interest in all of our equity interests and substantially all of our operating assets.

Under the indenture governing the Senior Notes, except for permitted tax distributions, we may not make distributions until certain conditions are satisfied. The indenture requires that we apply our net operating cash flow (i) first, to fund with monthly deposits our next semiannual payment of approximately $75.5 million of interest on the Senior 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 the Senior Notes. Distributions will be permitted only after Phase 1 target completion, as defined in the indenture governing the Senior Notes, or such earlier date as project revenues are received, upon satisfaction of the foregoing funding requirements, after satisfying a fixed charge coverage ratio test of 2:1 and after satisfying other conditions specified in the indenture.

F-27

SABINE PASS LNG, L.P.

A DEVELOPMENT STAGE ENTERPRISE

NOTES TO FINANCIAL STATEMENTS—(Continued)

(unaudited)

NOTE 7—Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported on the Balance Sheets for Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Accounts Receivable and Accounts Payable approximate fair value due to their short-term nature. We use available market data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107,Disclosures about Fair Value of Financial Instruments, and does not impact our financial position, results of operations or cash flows.

Financial Instruments (in thousands):

	March 31, 2007				December 31, 2006
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
2013 Notes (1)	$	550,000	$	554,125	$	550,000	$	547,250
2016 Notes (1)		1,482,000		1,489,410		1,482,000		1,478,295
	$	2,032,000	$	2,043,535	$	2,032,000	$	2,025,545

(1) The fair value of the Senior Notes was based on quotations obtained from broker-dealers who made markets in these and similar instruments as of March 30, 2007 and December 31, 2006.

NOTE 8—Related Party Transactions

As of March 31, 2007 and December 29, 2006, we had $1.3 million and $0.4 million, respectively, of advances to affiliates.

Service Agreements

Operation and Maintenance Agreement

In February 2005, we entered into an Operation and Maintenance Agreement (“O&M Agreement”) with Cheniere LNG O&M Services, L.P. (“O&M Services”), an indirect wholly-owned subsidiary of Cheniere Energy, Inc. (“Cheniere Energy”). Pursuant to the O&M Agreement, O&M Services has agreed to provide all necessary services required to construct, operate and maintain our 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 our LNG receiving terminal, we are 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 our LNG receiving terminal, 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 at the beginning of each operating year. In addition, we are required to reimburse O&M Services for its expenditures incurred, which are comprised of labor, maintenance, land lease and insurance expenses and for maintenance capital expenditures.

O&M Services has assigned the O&M Agreement to Cheniere Energy Partners GP, LLC, a wholly-owned subsidiary of Cheniere, and O&M Services and Cheniere Energy Partners GP, LLC have entered into a services and secondment agreement pursuant to which certain employees of O&M Services have been seconded to Cheniere Energy Partners GP, LLC to provide operating and routine maintenance services with respect to our LNG receiving terminal under the direction, supervision and control of Cheniere Energy Partners GP, LLC.

F-28

SABINE PASS LNG, L.P.

A DEVELOPMENT STAGE ENTERPRISE

NOTES TO FINANCIAL STATEMENTS—(Continued)

(unaudited)

Under this agreement, Cheniere Energy Partners GP, LLC pays O&M Services amounts that it receives from us under the O&M Agreement.

Management Services Agreements

In February 2005, we entered into a Management Services Agreement (the “Sabine Pass LNG MSA”) with Sabine Pass LNG–GP, Inc (“Sabine Pass GP”). Pursuant to the Sabine Pass LNG MSA, we appointed Sabine Pass GP to manage the construction and operation of our 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 our terminal use agreement with Total LNG USA, Inc. Prior to substantial completion of construction of our LNG receiving terminal, we are required to pay Sabine Pass GP 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, Sabine Pass GP entered into a Management Services Agreement with Cheniere LNG Terminals, Inc. (“Cheniere Terminals”), a wholly-owned subsidiary of Cheniere. Pursuant to this agreement, Cheniere Terminals provides Sabine Pass GP with technical, financial, staffing and related support necessary to allow it to meet its obligations to us under the Sabine Pass LNG MSA. Under this agreement with Cheniere Terminals, the Sabine Pass GP pays Cheniere Terminals amounts that it receives from us for management of our LNG receiving terminal.

NOTE 9—Commitments and Contingencies

Legal Proceedings

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, as of March 31, 2007 and December 31, 2006, there were no threatened or pending legal matters that would have a material impact on our consolidated combined results of operations, financial position or cash flows.

NOTE 10—Supplemental Cash Flow Information and Disclosures of Non-Cash Transactions

The following table provides supplemental disclosure of cash flow information (in thousands):

	Three Months Ended March 31,				Period from October 20, 2003 (Date of Inception) to March 31, 2007
	2007		2006
Cash paid for interest (1)	$	—	$	2,260	$	14,353
Construction-in-progress additions recorded as accrued liabilities	$	46,760	$	15,782	$	46,760

(1) All cash paid for interest was capitalized as construction-in-progress.

F-29

APPENDIX A

LEGAL NOTICE

This document was prepared by Stone & Webster Management Consultants, Inc. (“Stone & Webster Consultants”) solely for the benefit of Cheniere Energy Inc. (“Cheniere”). Neither Stone & Webster Consultants, Cheniere nor their parent corporations or affiliates, nor any person acting in their behalf (a) makes any warranty, expressed or implied, with respect to the use of any information or methods disclosed in this document; or (b) assumes any liability with respect to the use of any information or methods disclosed in this document.

Any recipient of this document, by their acceptance or use of this document, releases Stone & Webster Consultants, Cheniere, their parent corporations and affiliates from any liability for direct, indirect, consequential, or special loss or damage whether arising in contract, warranty, express or implied, tort or otherwise, and irrespective of fault, negligence, and strict liability.

E-MAIL NOTICE

E-mail copies of this report are not official unless authenticated and signed by Stone & Webster Consultants and are not to be modified in any manner without Stone & Webster Consultants’ expressed written consent.

A-2

NOMENCLATURE

ACI	American Concrete Institute
AISC	American Institute of Steel Construction
ANSI	American National Standards Institute
API	American Petroleum Institute
AQCR	Air Quality Control Region
ASCE	American Society of Civil Engineers
ASME	American Society of Mechanical Engineers
ASNT	American Society for Non-Destructive Testing
ASTM	American Society for Testing and Materials
AWS	American Welding Society
BACT	Best Available Control Technology
bcf	Billion Cubic Feet
bscfd	Billion Standard Cubic Feet per Day
Btu	British Thermal Unit
bpd	Barrels per Day
CAER	Community Awareness and Emergency Response
CATOX	Catalytic Oxidation Units
CO	Carbon Monoxide
COE	Corp of Engineers
CPI	Corrugated Plate Interceptor
CFR	Code of Federal Regulations
DCS	Distributed Control System
DSCR	Debt Service Coverage Ratio
DLE	Dry Low Emissions
DOT	Department of Transportation
DSAW	Double Submerged-Arc Welded
EPA	Environmental Protection Agency
EPC	Engineering, Procurement and Construction
FAA	Federal Aviation Administration
FEED	Front End Engineering Design
FERC	Federal Energy Regulatory Commission
FWS	Fish and Wildlife Service
HAZOP	Hazards and Operability
hp	Horsepower
IBC	International Building Code
IDC	Interest During Construction
IEC	International Electrotechnical Commission
IEEE	Institute of Electrical and Electronic Engineers
IMO	International Maritime Organization
IRR	Internal Rate of Return
ISA	Instrument Society of America
ISO	International Standards Organization
ITS	Interruptible Transportation Service
JV	Joint Venture
kV	Kilovolt
kW	Kilowatt
LDEQ	Louisiana Department of Environmental Quality

A-3

LNG	Liquefied Natural Gas
LS	Lump Sum
MMscfd	Million Standard Cubic Feet per Day
MP	Mile Post
MSS	Manufacturer Standardization Society
MW	Megawatt
NAAQS	National Ambient Air Quality Standards
NACE	National Association of Corrosion Engineers
NDE	Non-Destructive Examination
NEMA	National Electric Manufacturers Association
NFPA	National Fire Protection Association
NOx	Nitrogen Oxides
NOI	Notice of Intent
NOT	Notice of Termination
NPV	Net Present Value
O&M	Operations and Maintenance
OBE	Operating Basis Earthquake
OC	Operations Center
OCIMF	Oil Companies International Marine Forum
OSHA	Occupational Safety and Health Administration
OSRP	Oil Spill Response Plan
P&I	Protection and Indemnity
PLC	Programmable Logic Controller
PO	Purchase Order
PPE	Personal Protective Equipment
PSD	Prevention of Significant Deterioration
psia	pounds per square inch (absolute)
psig	pounds per square inch (gauge)
QA	Quality Assurance
QC	Quality Control
RAM	Reliability, Availability and Maintainability
SCR	Selective Catalytic Reduction
SIGTTO	Society of International Gas Tanker and Terminal Operations
SPCC	Spill Prevention and Containment Control
SQG	Small Quantity Generator
SSE	Safe Shutdown Earthquake
SSPC	Steel Structures Painting Council
TEMA	Tubular Exchanger Manufacturers’ Association
USCG	United States Coast Guard
V	Volt
VOC	Volatile Organic Compounds

A-4

Independent Technical Review Report

Sabine Pass LNG Terminal

1.0	Background	A-6
2.0	Summary of Risks	A-7
3.0	Project Description	A-13
4.0	Project Status	A-15
5.0	Project Implementation	A-16
6.0	Construction Budget	A-18
7.0	Construction Schedule	A-18
8.0	Environmental Risks	A-20
9.0	Operations and Maintenance Programs	A-20
10.0	Contracts	A-21
11.0	Conclusions	A-23
12.0	Site Visit Photographs	A-24

A-5

1.0    BACKGROUND

Cheniere Energy, Inc., the Sponsor, is based in Houston, Texas, USA. It originally established a fully owned subsidiary, Sabine Pass LNG, L.P. (“Sabine”) to develop, own and operate the Sabine Pass LNG Terminal Project (“Project”). The Project is located alongside the navigable Sabine River Channel in Cameron Parrish, Louisiana, directly across the river from Sabine Pass, Texas. It comprises a receiving and regasification terminal that will receive, store, and vaporize imported liquefied natural gas (“LNG”). Vaporized natural gas will be exported via natural gas pipeline to U.S. consumers. The Project will operate as a tolling terminal, processing LNG on behalf of two initial Terminal Use Agreement (“TUA”) Customers, Total LNG USA, Inc. and Chevron USA, Inc., who will own the imported LNG and the exported natural gas. The two TUA Customers have each reserved a LNG import and a regasification export capacity of approximately 1,000 million standard cubic feet of gas per day (“MMscfd”). A third TUA Customer, Cheniere Marketing, Inc. (“Cheniere”) has reserved a maximum capacity of approximately 2,000 MMscfd. At this time Cheniere has not yet executed a LNG Off-take Agreement with any LNG liquefaction facility to secure an LNG supply to process through the Project. The terminal was originally designed to import sufficient LNG to produce a maximum peak natural gas export capacity of approximately 2,600 MMscfd. This is termed the Phase I Project. In mid-2006, the Phase 2 Stage 1 Expansion Project (the “Phase 2 Project”) was implemented. Upon completion, this will increase the maximum peak export capacity to approximately 4,000 MMscfd.

The Phase 1 Project is being implemented under a lump sum turnkey EPC Contract by Bechtel Corporation, (“Bechtel” or the “EPC Contractor”). Principal subcontractors include Mitsubishi Heavy Industries Ltd. (“MHI”) with Matrix Services (jointly “MHI/Matrix”) for the LNG tanks, Weeks Marine Inc. (“Weeks”) for the marine terminal, and Remedial Construction Services, L.P. (“Recon”) for site preparation and soil improvement. Bechtel is also the general EPC Contractor for Phase 2 under a reimbursable form of contract. In addition, Bechtel is providing construction management services to assist Sabine with managing the other principal fixed-price Phase 2 EPC Contractors, a joint venture of Diamond LNG (an MHI company) and Zachry (“Diamond/Zachry”) for the two additional LNG Tanks, and Recon for site preparation and soil improvement.

The U.S. Federal Energy Regulatory Commission (“FERC”) issued approval for the Phase 1 Project on December 21, 2004. Limited Notice to Proceed was issued under the Phase 1 EPC Contract on January 4, 2005. Subsequently, the full Notice to Proceed was issued on April 4, 2005. The Guaranteed Substantial Completion Date was originally September 2, 2008; however, a hurricane Force Majeure Change Order has revised the date to December 20, 2008. Full utilization of the terminal by the two TUA Customers is to commence by April 1, 2009 for Total and by July 1, 2009 for Chevron.

In July 2005 Sabine submitted a permit application to FERC for the Sabine Pass LNG Terminal Phase 2 Expansion Project. Approval was granted on June 15, 2006. Stage 1 of the Phase 2 Expansion Project will increase the peak terminal throughput capacity by 1,400 MMscfd to the ultimate peak capacity of 4,000 MMscfd. Change orders were issued during the construction of the Phase 1 Project to provide tie-ins and other pre-investment work necessary to minimize potential construction and operations interferences to Phase 1 activities during the execution of the Phase 2 Expansion Project. Cheniere undertook a substantial engineering effort and committed pre-investment expenditure to identify and mitigate potential interferences by Phase 2 on the timely completion and operation of Phase 1. In Stone & Webster Consultants’ opinion, the Phase 2 Stage 1 Expansion of Sabine Pass poses negligible risk to the timely completion and operation of the Phase 1 Project.

A-6

Aerial View from the North During Site Preparation

Stone & Webster Management Consultants, Inc. (“Stone & Webster Consultants”) was retained by Cheniere Energy, Inc. to conduct an independent technical assessment of the Project on behalf of the potential investors. Stone & Webster Consultants’ independent technical review report (“Report”), including the observations and conclusions presented herein, is based on, among other things, our review of the available technical, performance, schedule and cost data, visits to terminal site, and interviews with Cheniere personnel. The Report presents our findings and conclusions regarding the following:

• Plant design and technology;

• Project execution plans and implementation schedule;

• Capital costs;

• Expected plant performance and operating parameters;

• Operations and maintenance programs and budgets; and

• Environmental permitting and regulatory issues.

2.0    SUMMARY OF RISKS

As indicated above, the Terminal is being implemented in two phases under different contracting strategies. The primary revenue for the Project is derived from the Total and Chevron TUAs. Accordingly, Stone & Webster Consultants has considered areas where there is perceived technical risk to the implementation of the Phase 1 Project and areas where the Phase 2 Expansion Project and its operation could impact the Phase I Project. Particular focus has been placed on circumstances where the risk component could materially impact the projected cash flows. Tables 2.0-1 and 2.0-2 present a summary of our assessment of these risks.

A-7

Table 2.0-1

Phase 1 Project Risks

Risk Component	Comment
LNG Supply Low Risk	This is a Terminal User obligation under the terms of the TUAs with Total and Chevron.
Technology Low Risk	In general, the Project is using established and suitable technology for the Project. Stone & Webster Consultants is of the opinion that the process facilities to be installed at the terminal are robust and should provide for a long and useful service life. Likewise Stone & Webster Consultants confirms that there are no unusual risks regarding the technology proposed for LNG receipt, LNG storage, or regasification.
Scale Up Low Risk	In Stone & Webster Consultants’ opinion, there is no scale-up risk associated with the Project. All major equipment is proven at the proposed size and capacity levels. Furthermore, the combined LNG export capacity of the two initial TUA Customers is 2,000 MMscfd versus a nameplate export rating of 2,600 MMscfd, thus providing ample excess capacity to service the two primary TUAs..
Environmental Issues Low Risk	Stone & Webster Consultants’ review has not identified any environmental issues that would have an undue effect upon either the Project construction schedule or budget, and compliance with local, state and federal requirements will result in full compliance with the Equator Principles.
Regulatory Issues Low Risk	The Sponsor has identified the appropriate permits and other regulatory approvals required for this Project, including the LNG carrier transit, berths and unloading facilities; the LNG storage and regasification units; power generation; and other infrastructure and auxiliary facilities. In Stone & Webster Consultants’ opinion, the Sponsor is making satisfactory progress towards obtaining the requisite approvals in a timely manner that supports the proposed construction schedule. Total and Chevron will jointly, but separately apply for a send-out pipeline permit to export their gas from the Terminal. On December 21, 2004, FERC issued theOrder Granting Authorization under Section 3 of the Natural Gas Act (“FERC Order”) to Sabine Pass LNG, L.P., authorizing Sabine to construct an LNG terminal and send-out pipeline. The Louisiana LDEQ has issued Sabine a PSD air emissions permit. Sabine received its final construction permit from the U.S. Army Corps of Engineers.
Contracting Strategy and Project Execution Low to Medium Risk	The EPC Contractor is Bechtel Corporation, a skilled and experienced contractor with a long proven track record in the engineering, procurement and construction of energy-related projects, including LNG liquefaction and regasification facilities. The LNG storage tanks will be subcontracted to a consortium of MHI and Matrix Services. The marine terminal and associated dredging have been subcontracted to Weeks Marine, an experienced and reputable marine contractor. Site preparation and pile installation has been subcontracted to Recon, a skilled and experienced civil engineering contractor. In Stone & Webster Consultants’ opinion, each of these firms has the requisite experience and capability to undertake the assigned role for the implementation of the Project.

A-8

Risk Component	Comment
	Cheniere is a start-up company and does not have sufficient permanent in-house personnel to properly and fully staff the Project Management Team, during Project execution. Therefore the Sponsor will hire temporary contract personnel and consultants to fill the open PMT positions. This organizational structure is typical for projects of this size and complexity, even by well-established major oil and gas corporations, due to previous downsizing. The PMT personnel have not previously worked together as a team and therefore have gone through a learning curve period.
Capital Cost Low to Medium Risk	The EPC Contract portion of the Phase 1 Project cost is being implemented under a LSTK contract with Bechtel. In our opinion, the Owner’s Costs properly reflect the responsibilities and risks carried by the Owner. The Total Phase 1 Project Costs is currently budgeted to fall in the range of US$900 to US$950 million. Stone & Webster Consultants has reviewed the detailed build-up of both the EPC Contract Cost and the Owner’s Costs. In our opinion, based upon our benchmarking of this Capital Expenditure (“CAPEX”) against that of comparable projects, the budget is reasonable.
Operating Cost Low Risk	Operations, maintenance and contract labor costs total US$10.0 million per annum. Other fixed operating costs amount to US$15.1 million per annum in the aggregate. Apportioned Cheniere G&A costs carried by the Project add $8.3 million, and the GE power generation maintenance expenses add a further US$3.2 million, bringing the total annual (Phase 1) O&M costs for year 2010 to US$36.6 million. Based on Stone & Webster Consultants’ experience with similar LNG receiving and regasification terminals world-wide, these O&M expenses fall well within industry benchmarks for similar facilities. Based upon the benchmark comparison, the O&M Budget estimate is reasonable. Moreover, the OPEX reimbursement provisions provided by the two primary TUAs cover any reasonable overage above the current O&M cost estimate.
Operating Performance Low Risk	In Stone & Webster Consultants’ opinion, the proposed facilities pose no unusual operating risks for a facility of this nature. The Sponsor has not commissioned a Reliability, Availability, and Maintainability (“RAM”) Analysis for the Project, but the expected availability of the individual tandem vaporization units is expected to be approximately 96 percent. Based on Stone & Webster Consultants’ experience, the re-gasification and export availability for all sixteen of the Phase 1 vaporizers should be approximately 81.5 percent. This means at least thirteen vaporizers should be fully available at all times. This results in a minimum continuous export availability of approximately 2,340 MMscfd versus the export capacity under the two primary TUAs of 2,000 MMscfd. The required export capacity of 2,000 MMscfd is equivalent to 90,500 cubic meters per day of LNG in liquid form. The available Phase 1 LNG storage capacity is 480,000 cubic meters, resulting in a storage-to-export ratio of 5.3:1 The industry norm is approximately 4:1, so the terminal has ample storage capacity to service the two primary TUAs.

A-9

Risk Component	Comment
Operating Performance Low Risk	The required LNG reception quantity including retainage is approximately 90,500 cubic meters per day, which can be supplied on average by one 140,000 cubic meter LNG carrier every 36 hours. Given the availability of two independent unloading berths, Stone & Webster Consultants has no significant concerns regarding LNG receiving capacity, even accounting for unavailability due to inclement weather.
Interfaces Low to Medium Risk	The respective Customers of the Terminal are responsible for providing pipeline interconnections between the Terminal and the existing export natural gas pipeline grid connections. The main export line should be approximately 16 miles long to the principal connections tie-in points. Marine support facilities, e.g., tugs and line handling boats are the responsibility of the Terminal Users; however, Sabine will assist in securing and managing these services. Drinking water will be supplied in bottled form by local suppliers. Utility water will be provided via pipeline from a local supplier. Power will be supplied internally by three LM2500+ simple-cycle gas turbine-driven generators. Only two of the turbines are required for the export capacity required by the two primary TUAs. There will be no external power supply.
Geography Low to Medium Risk	Meteorological conditions for the site and the Gulf of Mexico are well understood. The site is within the hurricane belt. The design applies appropriate criteria to mitigate the impact of hurricanes.

Table 2.0-2

Phase 2 Stage 1 Expansion

Risk Component	Comment
Supply Low Risk	A third TUA has been executed with another Cheniere affiliate, Cheniere Marketing, Inc, but per Stone &Webster Consultants’ understanding, Cheniere has not yet contracted with any LNG liquefaction facility to supply Cheniere with LNG for processing through the Terminal.
Technology Low Risk	The Expansion Project is using proven technology for the tanks and vaporizers. The LNG Berths are being extended using open cell bulkhead technology to accommodate LNG carriers larger than 250,000 cubic meters. Open cell technology has been demonstrated to be effective in over 140 projects in Alaska and the Contiguous 48 States.
Scale Up Low Risk	The Project is using established equipment sizes. Equipment is identical to that used for Phase 1.
Regulatory Issues Low Risk	The Project is governed by established federal, state and local regulations. FERC issued its Authorization Order for the Phase 2 Expansion Project on June 15, 2006.

A-10

Risk Component	Comment
Environmental Issues Low Risk	Stone & Webster Consultants’ review did not identify any environmental issues that would have an adverse effect on the Project cost, schedule or operation.
Equator Principles Issues Low Risk	The EA complies with the requirements of the Equator Principles. In Stone & Webster Consultants’ opinion, compliance with State and Federal requirements will result in full compliance with the Equator Principles.
Impact of Expansion on Phase 1 Low Risk	There are no unmanageable potential impacts or conflicts between Phase 1 and the Phase 2 Stage 1 Expansion Project. The Phase 2 Stage 1 expansion can be constructed, commissioned and operated without detriment to the Phase 1 facilities. Significant care has been given to ensuring that the Phase 2 Stage 1 Expansion of Sabine Pass poses negligible risk to the timely completion and operation of the Phase 1 Project.
Contracting Strategy and Project Execution Low to Medium Risk	In general, Sabine has opted to contract with the same contractors and principal suppliers as used for the Phase 1 Project. Bechtel serves as the main EPCCm Contractor, Diamond-Zachry for the construction of the two new LNG storage tanks, and Recon for soils remediation. In Stone & Webster Consultants’ opinion, each of these firms has the requisite experience and capability to undertake the assigned role for the implementation of the Project. In addition, Stone & Webster Consultants confirms that this contracting strategy should minimize any conflict between like contractors on the two phases of the Project. Sabine has selected a cost-reimbursable contracting philosophy for the majority of the Phase 2 Expansion Project that is designed to maximize its flexibility. A lump sum contract has been selected for the LNG tanks albeit with a labor escalation clause. Material costs were fixed following execution of the contract. These tanks are essentially identical to the three Phase 1 tanks. Zachry rather than Matrix is partnering with Diamond as the tank constructor. In Stone & Webster Consultants’ opinion, the contracting strategy is designed to ensure that the Phase 2 Stage 1 Expansion Project poses negligible risk to the timely completion and operation of the Phase 1 Project. Sabine has established a dedicated Project Management Team. Sabine will also use Bureau Veritas and other contract personnel, term contract personnel, and possibly personnel from other EPC contractors to supplement the Project Management Team. These positions will be filled as needed as the Project execution progresses. This organizational structure is typical for projects of this size and complexity, even by well-established major oil and gas corporations, due to previous downsizing. However, these PMT personnel have not previously worked together and will require a learning curve period before the team can efficiently and effectively oversee the various EPC Contractors and facilitate resolution of the detailed technical and execution queries that inevitably arise during execution of such a Project. This represents a medium risk to the Sponsors.

A-11

Risk Component	Comment
Project Schedule Low Risk	Completion of the Phase-2 Expansion is not schedule-critical for Sabine’s debt holders. The 36-month schedule for Phase 2 is challenging but achievable.
Capital Cost Low to Medium Risk	The EPC Contract portion of the Phase 2 Project cost is being implemented under a reimbursable EPCCm contract with Bechtel and under fixed-price EPC Contracts with other contractors. In our opinion, the Owner’s Costs properly reflect the responsibilities and risks carried by the Owner. The Total Phase 2 Stage 1 Project Cost is currently budgeted to fall in the range of US$500 to US$550 million. Stone & Webster Consultants has reviewed the detailed build-up of both the EPC Contract Cost and the Owner’s Costs. In our opinion, based upon our benchmarking of this Capital Expenditure (“CAPEX”) against that of comparable projects, including the Phase 1 Project, the budget is reasonable.
Operating Cost Low to Medium Risk	Operations, maintenance and contract labor costs total US$10.0 million per annum. Other fixed operating costs amount to US$15.8 million per annum in the aggregate. Apportioned Cheniere G&A costs carried by the Project add $8.3 million, and the GE power generation maintenance expenses add a further US$4.6 million, bringing the total annual (Phase 1) O&M costs for year 2010 to US$38.7 million, a US$2.1 million increase over Phase 1. Note: fuel for regasification is provided by the Terminal Users.
Interface with Existing Infrastructure Low Risk	Tie-ins to the existing Phase 1 Project have been provided to minimize/eliminate tie-in issues. Expansion of the LNG Berths to accommodate larger LNG carriers is not on the critical path. It will be undertaken before mid-2007 and will not impact operation of the berths during Phase 1.
Interface with Existing Infrastructure Low Risk	Total and Chevron have contracted with the proposed Kinder Morgan LP (“KMLP”) pipeline for the transportation of their natural gas. Sabine will have unhindered access to the Cheniere Sabine Pass Pipeline, L.P. (“CSPP”) pipeline for export of gas from the facilities to service the Cheniere LNG Marketing TUA and for Phase 1 commissioning and performance testing, which will occur before the KMLP is commissioned.
Logistics Low to Medium Risk	The Expansion site has been provided with separate ingress and egress and separate laydown areas from the Phase 1 Project. The Phase 1 Project and Phase 2 Expansion Project will share use of the common Construction Dock. Detailed planning will facilitate coordination of the use of this facility, but Phase 1 will always have priority access. A dedicated crane and crew will be provided at the Construction Dock to expedite access to all parties. The Phase 1 Project is proving to be a preferred work location for local craft labor due to the duration of the combined Projects. The time-lag between phases should facilitate Bechtel Home Office and construction labor moving from Phase 1 to the Phase 2 Project.
Geography Medium Risk	The site is located on the US Gulf coast in an area that is prone to hurricanes. The Phase 1 Project was affected by Hurricane Katrina and Rita during 2005. Primary risk pertains to the construction period when facilities are incomplete.

A-12

3.0    PROJECT DESCRIPTION

3.1    Site

The Sabine Pass LNG plant site is situated on an area once utilized by the U.S. Army Corps of Engineers as a depository for Sabine/Neches Waterway dredging spoils; hence the soils at the site require substantial remediation and enhancement.

3.2    Facilities

The Phase 1 Project consists of the following principal components:

• Marine receiving terminal capable of unloading two LNG carriers simultaneously. The marine terminal consists of two LNG carrier unloading docks, each capable of unloading an LNG carrier with cargo capacity in the range from 87,600 cubic meters to 250,000 cubic meters of LNG. The Sponsor anticipates that a 250,000 cubic meter LNG carrier will have a draft of 39.4 feet. The US Coast Guard (the “USCG”) states that the shipping channel is currently maintained at 40 feet of depth which is adequate to accommodate current LNG carriers, which have a maximum draft of approximately 37.4 feet. However, recent soundings tabulated by NOAA and data contained in the Vessel Maneuvering Simulation Study indicate channel depths of 42 feet, and that areas of the pass channel have depths of 45 feet. Sponsor will dredge the berth/terminal area to a depth of 45 feet below mean low water line plus two feet of over dredge. The deeper depth of the berths will permit Sabine to better monitor the rate of sedimentation accumulation to better plan future dredging operations.;

• Three 160,000 cubic meter single containment LNG storage tanks. Each tank is designed for a working tank volume of 160,000 cubic meters, or approximately 1,006,400 barrels. This type of tank comprises an inner LNG containment tank fabricated from nine-percent nickel steel, suitable for the cryogenic storage temperature of approximately (-)260°F. The inner tank is then surrounded by an outer carbon steel tank, which retains the perlite insulation material, which is poured into the annular area between the two tank walls. Each LNG storage tank is enclosed within an individual earthen dike or berm designed to contain 110 percent of the maximum tank volume in the event of a tank rupture. In the U.S., this diked volume is a requirement of federal regulation 49CFR193, which is followed rigorously by the Federal Energy Regulatory Commission (“FERC”);

• LNG circulation system to keep unloading systems cold between LNG shipments;

• LNG tank and LNG carrier vapor handling systems ;

• Storage tank boil-off gas compressors and re-condenser systems;

• Three LNG in-tank transfer pumps in each tank. The sendout pumps will be multi-stage, seal-less vertical centrifugal pumps, with the entire pump and motor submerged in, in accordance with accepted industry practice;

• Sixteen LNG high pressure export pumps submerged in a pumpout vessel supplied with the pump and Submerged Combustion Vaporizers (“SCV”). Each SCV is designed with an absorbed heat duty of approximately 116.0 MMBtu per hour, a well-proven capacity level. Vaporizers are essentially self-contained package units, complete with fully integrated burner management systems and safety interlocks. The SCV package also includes the electric motor-driven combustion air blower, which compresses air up to the submerged combustion pressure. SCVs are robust units, currently employed in approximately 75 percent of the world’s LNG regasification terminals, and thus represent very little risk;

A-13

• Natural gas metering stations and export pipeline header;

• Electric power generation and distribution. This comprises three LM 2500+ aeroderivative gas turbine driven generator sets, which are well-proven in the industry:

• Utilities, infrastructure, and support facilities.

The Phase 1 marine terminal consists of two LNG carrier unloading docks, each capable of unloading LNG carriers of between 87,600 cubic meters and 250,000 cubic meters of LNG storage capacity.

Phase 2 comprises the addition of:

• Modifications to the original berth design by adding approximately 100 feet of additional clearance at the stern of docked LNG carriers by replacing the rock rip-rap covered, sloped underwater shore with vertical bulkhead constructed using open-cell technology developed and patented by PND Incorporated (“PND”), headquartered in Anchorage, Alaska.

• eight tandem vaporization units, each consisting of a high pressure send-out pump coupled to a SCV designed to vaporize approximately 180 MMscfd;

• two additional 160,000 cubic meter LNG storage tanks;

• a fourth GE (LM-2500+) gas turbine power generation unit;

• a partial Ambient Air Vaporizer (“AAV”) train, consisting of 11 cells, to serve as a pilot testing facility. The use of AAV technology has potential operating cost reduction benefits in the summer months. A full AAV train comprises 33 cells and has a design vaporization capacity of 180 MMscfd.

• a new Auxiliary Control Building;

• a new electric power Substation;

• a fourth instrument and utility air compression unit;

• additional utilities and infrastructure facilities to support the overall expansion program;

• additional tie-ins and other pre-investment work required to minimize potential construction and operations interferences due to the addition of the subsequent Phase 2 expansion stages.

3.3    Operation

Pumps onboard an LNG carrier are used to unload LNG and transfer it to the storage tanks. As the LNG enters a storage tank, vapor in the tank is displaced. This cold vapor is returned to the LNG carrier to replace the equal volume of unloaded LNG and maintain constant pressure in both the tank and the carrier. This vapor is returned to the carrier via cryogenic blowers. Similarly, between LNG deliveries, a small amount of LNG will be circulated from the storage tanks through the carrier unloading lines to keep them at cryogenic unloading temperature. LNG is pumped from each storage tank by in-tank submerged transfer pumps. These discharge LNG from the tank at approximately 85 psig. Excess tank vapor is compressed to 85 psig. Vapor re-condensers then condense and re-absorb the compressed vapor into the pressurized LNG pumped from the tanks. Multi-stage export pumps boost the pressure of the LNG to 1550 psig. This high-pressure LNG is fed to submerged combustion vaporizers (“SCV”). Each pump feeds one SCV. A total of sixteen pump/vaporizer tandem sets are provided under Phase 1, each with a design export capacity of approximately 180 MMscfd. Achieved capacity depends on the LNG composition. A small amount of the vaporized export gas, less than two percent of the total capacity, will be consumed internally as fuel gas for the terminal. Export gas will be routed through a metering station into the main export pipeline header, which is connected to numerous natural gas distribution pipelines. All export pipeline infrastructure downstream of the metering station is to be supplied by others.

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The Phase 1 Sabine Pass LNG Terminal will generate its own electric power from two operating General Electric (LM-2500+) gas turbine-driven generators plus one spare unit. Maximum expected power consumption is approximately 50 MW, compared to an installed capacity of 75 MW. Under Phase 2 a fourth LM-2500+ turbine-generator unit will be added. At the maximum peak export capacity of 4,000 MMscfd, three of the four generators will be required for full Terminal operations, with the fourth unit available as a stand-by spare.

4.0    PROJECT STATUS

4.1    Basis of Opinion

Stone & Webster Consultants’ evaluation of the current status of the Project is based on our review of the Phase 1 and Phase 2, December 2006 Monthly Progress Reports issued by Bechtel, and a site visit on January 18, 2007. Photographs taken during this site visit are included in Section 12 of this report.

4.2    Phase 1

Cumulative aggregate progress of the Phase 1 Project through the end of December 2006 was 68.2 percent compared to with planned progress of 69.3 percent. The Project has two near parallel critical paths, one relating to the LNG Tanks which has three days of float for LNG Tank 2 and the other relating to the power generation facilities which has nine days float. Progress on these two critical paths is such that Bechtel is expected to achieve the Target Bonus Date of April 3, 2008, which corresponds to completion of the main terminal and two of the three LNG Tanks and to a demonstrated export capacity of 2,000 MMscfd. The Base Milestone Schedule is based on the Target Bonus Date, which by definition began with zero days of float, where it currently remains. The Scheduled Substantial Completion Date which corresponds to completion of the entire terminal and demonstration of the maximum peak export capacity of 2,730 MMscfd, is currently scheduled for November 8, 2008, versus the Guaranteed Substantial Completion Date of December 20, 2008, which corresponds to 34 days of float. Therefore, the Project is currently proceeding in accordance with the Construction Budget and Schedule.

At the end of December 2006, engineering progress was 97.6 percent versus the baseline plan of 97.6 percent. Engineering will be completed once Substantial Completion is achieved and as-built drawings are developed. Procurement progress was 93.0 percent versus the plan of 93.0 percent. Construction progress was reported as 53.8 percent versus the plan of 55.6 percent. Construction progress during the last quarter of 2006 was adversely impacted by an unusual amount of rain which resulted in six lost work days. The lost work days could not be recovered by the end of December due to reduced manning during the Holiday Season. Stone & Webster Consultants notes that early January 2007 was also unusually wet, further impacting progress.

The full impacts of the 2005 hurricane season on Bechtel, the primary EPC Contractor, and the LNG tank and the marine terminal subcontractors were fully integrated into the schedule during November 2006. The Target Bonus Completion Date still remains as April 3, 2008, with zero days of float as noted above. The Guaranteed Substantial Completion Date has 34 days of positive float, indicating that this date will likely be achieved. Schedule Delay Liquidated Damages are associated with missing this contractual Milestone Date.

4.3    Phase 2 Stage 1

The Engineering teams are focused upon preparations for the first Phase 2 HAZOP Review to commence in mid-January, which will include all major facilities. However, there have been some delays in issuing piling construction drawings due to P&ID delays. The Procurement team issued commitments for large-bore welded stainless pipe and fittings, the Submerged Combustion Vaporizers, and Ambient Vaporizers in December. Purchase orders for the cryogenic LNG pumps will be awarded in January. The Phase 2 Project is currently undergoing soil stabilization and enhancement, and Bechtel and other Phase 2 contractors will be mobilizing to

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the site over the next two months. The early construction management team has also mobilized to the site to oversee Recon’s Phase 2 site preparation work. Recon turned over the LNG Tank 4 site for pile driving and plans to turn over the LNG Tank 5 site in January. Pile driving has begun in one piperack area.

The overall Project Control Schedule has not yet been finalized so baseline progress curves have not yet been developed. Stone & Webster Consultants is somewhat concerned about this, since this was to have been finalized and accepted by all parties by the end of November 2006, in accordance with the Bechtel EPC Contract for Phase 2. According to the December Progress Report, the Project Control Schedule will be issued in January and the Control Estimate will be presented to Sabine by late February 2007.

5.0    PROJECT IMPLEMENTATION

5.1    Codes and Standards

In the Project documentation, the Sponsor required that all Project facilities are to be specified, engineered, procured, constructed, operated and maintained in accordance with all applicable Federal and state regulations and accepted industry practices and guidelines. The primary requirements for this federally regulated Project are mandated by the United States Federal Energy Regulatory Commission (“FERC”), which principally refer to 49 CFR 193 and NFPA 59A. These regulations are further augmented by the International Maritime Organization, Society of International Gas Tanker & Terminal Operators Ltd. (“SIGTTO”), and other applicable industry standards and codes which are required and incorporated by reference in the regulations and documents promulgated by these entities. The industry guideline adopted by SIGTTO is specifically referenced in the two Terminal Use Agreements (“TUA”) between Sabine Pass LNG, L.P and the Project’s anchor Customers, Total LNG USA, Inc. and Chevron USA Inc. Equipment provided under both Phase 1 and Phase 2 incorporates the latest technology updates with respect to high efficiency performance and low emissions. Thus the Project will represent little risk from an equipment performance and reliability perspective. Based on the foregoing requirements, in Stone & Webster Consultants’ opinion, the design is consistent with that of similar facilities within the United States and abroad and should result in an LNG terminal facility capable of fulfilling the commitments made under the TUAs.

5.2    Phase 1 Contracting Strategy

Cheniere contracted Bechtel to undertake the FEED for the Project. It pre-selected MHI/Matrix as the LNG Tank Subcontractor, Weeks Marine as the Marine Subcontractor, and Recon as the Soils Improvement Subcontractor. In addition, Cheniere limited bidding and negotiation on certain long-lead equipment to one or two vendors, including T-Thermal for the submerged combustion vaporizers, IHI for the boil-off gas compressor, and FMC and Connex SVT for the unloading arms. It then negotiated with Bechtel on an open-book estimate basis to provide a lump sum price for turnkey EPC Contract for the Project. Stone & Webster confirms that the selected subcontractors and equipment suppliers have the expertise and experience to perform the specified work or provide the equipment.

5.3    Phase 2 Contracting Strategy

Sponsor provided the following draft contracts and agreements for our review and comment:

• Reimbursable Bechtel EPCCm Contract,;

• Fixed Price Diamond/Zachry EPC LNG Tank Contract;

• Unit Rate Recon EPC Contract for Soils Improvement;

All of these contracts were subsequently executed on July 21, 2006.

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In addition, we reviewed the executed Willbros/CSPC EPC Contract for Cheniere Sabine Pass Pipeline Project, dated February 1, 2006.

Sabine executed a reimbursable EPCCm Contract with Bechtel that will provide engineering, procurement and construction management services together with direct hire construction services for those activities not provided by other contractors.

The reimbursable form of contract requires additional diligence and oversight by Sabine, especially when Phase 1 and Phase 2 work is being undertaken concurrently by the same contractor but paid under different compensation arrangements. Sabine issued its “Notice to Proceed” to Bechtel on July 26, 2006

The Phase 1 scope of work is proceeding under a fixed price, lump-sum turn key contract format. In contrast, the Phase 2 Project is being executed using a combination of individual reimbursable or unit rate contracts between Sabine and selected contractors and a reimbursable time and material contract with Bechtel responsible for all work not directly contracted by Sabine including detailed engineering, procurement and construction services. Bechtel will also serve as Sabine’s overall Construction Manager, in overseeing all contractors for the Phase 2 Expansion project. Under this arrangement Sabine retains total responsibility for risks associated with project scope and also assumes the risk for cost increases associated with labor productivity.

In Stone & Webster Consultants’ opinion, Sabine has selected a contracting scheme that facilitates and complements its goal to minimize any interference between Phase 1 and Phase 2 activities. The contracting strategy recognizes the changes in the EPC contracting environment over the past two years, in particular the reluctance of contractors to bid large lump sum EPC contracts on the US Gulf Coast. Moreover, the contracting strategy also recognizes the benefits afforded under the Phase 1 lump sum contract by utilizing the same key contractors and vendors. The contracts reflect generally acceptable provisions and terms that do not impinge upon the Phase 1 Project. Overall, the Phase 2 contracting strategy provides Sabine with flexibility should it be necessary to change the mode or order in which the work is executed.

5.4    Foundations

The Sabine Pass LNG plant site is situated on an area once utilized by the U.S. Army Corps of Engineers as a depository for Sabine River Channel dredging spoils. Dredged soils in the tank areas have been stabilized to a depth of 12 feet below grade. All foundations for major equipment and structures, including the LNG storage tanks, LNG process equipment, pipe racks and marine terminal equipment, are piled. Project specifications required field testing of at least four piles per tank that support the LNG storage tank foundation. Final pile design for the tank foundation piles was determined from these test results.

5.5    Implications of Phase 2 on the Phase 1 Project

Management and co-ordination of the Phase 1 Project and the Phase 2 Stage 1 Expansion Project present challenges that can be met by careful early planning and diligent attention to execution. Accordingly, Sabine and Bechtel have developed procedures and execution plans that address potential interferences or conflicts between the two projects. The potential adverse effect of the Phase 2 Expansion on the Phase 1 Project is mitigated substantially by the one-year lag between the two Project schedules. Essentially all Phase 1 engineering, procurement, and initial construction activities will be completed before those for Phase 2 commence. Sabine has performed a comprehensive scheduling analysis of the common utilization of the full-time crew and crane at the Construction Dock. This analysis indicates no unmanageable conflicts. Sabine represents that it will provide an experienced and adequately staffed Project Management Team and supporting Owner’s Engineer personnel to properly oversee Bechtel and the other Expansion Project contractors. Sabine and Bechtel will provide a user-friendly, logic-linked Critical Path Method (“CPM”) control schedule as quickly as practical to allow detailed

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planning especially of tie-ins to the Phase 1 facilities, as well as common use of the Construction Dock and public access roads by all parties, including the two export pipeline projects. Stone & Webster Consultants confirms that this is consistent with good industry practice.

Sabine and Bechtel have implemented enhanced compensation programs to attract and retain skilled construction craft labor for both Projects. Should competition with outside projects drawing on the same labor resource create overall labor shortages at the Sabine site, Phase 1 will have absolute priority to available labor resources. Sabine plans to hire extra operations personnel on a term-contract basis to satisfy operations requirements of both Phases. The term-contract personnel will be released upon achievement of full operational status for the entire expanded facility. Total and Chevron have contracted to use the proposed KMLP pipeline for the transportation of their natural gas, thus completely freeing up the CSPP pipeline for unhindered access by Sabine for commissioning, performance testing of both Phase 1 and Phase 2, and for normal operation of the Phase 2 Stage 1 facilities in servicing the Cheniere TUA export volumes.

Given these scenarios and the overall Phase 2 Stage 1 Project Execution Plan, in Stone & Webster Consultants’ opinion, there are no unmanageable potential impacts, interferences or conflicts between the Phase 1 Project and the Phase 2 Stage 1 Expansion Project in terms of engineering, procurement, construction, commissioning, and performance testing, nor in terms of the achievement and continuation of normal operational status.

6.0    CONSTRUCTION BUDGET

6.1    Phase 1 Budget

The EPC Contract portion of the Phase 1 Project cost is being implemented under a LSTK contract with Bechtel. In our opinion, the Owner’s Costs properly reflect the responsibilities and risks carried by the Owner. The Total Phase 1 Project Costs is currently budgeted to fall in the range of US$900 to US$950 million. Stone & Webster Consultants has reviewed the detailed build-up of both the EPC Contract Cost and the Owner’s Costs. In our opinion, based upon our benchmarking of this CAPEX budget against comparable projects, the budget is reasonable.

6.2    Phase 2 Budget

The EPC Contract portion of the Phase 2 Project cost is being implemented under a reimbursable EPCCm contract with Bechtel and under fixed-price EPC Contracts with other contractors. In our opinion, the Owner’s Costs properly reflect the responsibilities and risks carried by the Owner. The Total Phase 2 Stage 1 Project Cost is currently budgeted to fall in the range of US$500 to US$550 million. Stone & Webster Consultants has reviewed the detailed build-up of both the EPC Contract Cost and the Owner’s Costs. In our opinion, based upon our benchmarking of this CAPEX budget against comparable projects, including the Phase 1 Project, the budget is reasonable.

7.0    CONSTRUCTION SCHEDULE

7.1    Phase 1

The Force Majeure impacts from the hurricanes, resulting in extension of the Guaranteed Substantial Completion Date from September 2, 2008 to December 20, 2008, have been incorporated into the updated Level III CPM Schedule. The revised key contractual Project Milestone dates are summarized below in Table 7.1-1.

Bechtel’s primary critical path runs through the LNG Storage tanks, with RFCD of LNG Tank 2 scheduled for March 21, 2008, with zero float. A near parallel secondary critical path runs through startup of the power generation facilities, which is scheduled for September 13, 2007. This activity currently has nine days of positive float. This means that the actual startup of these facilities can still slip 9 working days without impacting

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achievement of the Target Bonus Date. Timely startup of the power generation facilities is essential to Bechtel being able to pre-commission and commission the entire terminal. The scheduled Target Bonus Date of April 3, 2008 continues to indicate zero days of float, as this was the original reference point for the development of the Milestone Schedule. However, the days of float for this reference Milestone Date can change as other milestones experience acceleration or deceleration. In Stone & Webster Consultants opinion, field construction is being undertaken in a well-managed and proactive manner. Once engineering and procurement constraints are removed, Stone & Webster Consultants expects actual construction progress to generate float and achieve the Target Bonus Date of April 3, 2008

Table 7.1-1

Scheduled Key Milestone Dates

Milestone Description	EPC Contract Basis	Early Finish	Late Finish
FERC Approval	Condition Precedent	Dec 21, 2004	Completed
Limited Notice to Proceed (LNTP)	On or Before Jan 4, 2005	Jan 4, 2005	Completed
Notice to Proceed (NTP)	Min 90 days after LNTP	April 4, 2005	Completed
Approved Perf. Test Procedures	By 24 Months after NTP	April 4, 2007	April 4, 2007
Submit Target Bonus Test Procedures		Jan. 7, 2008	Jan. 18, 2008
Ready For Cool Down System #1	Terminal plus Tank No.1	Feb 18, 2008	Feb 28, 2008
Ready For Cool Down System #2	LNG Tank No.2	March 21, 2008	March 25, 2008
Target Bonus Date (2000 MMscfd)	1095 days after NTP	April 3, 2008	April 3, 2008
Ready For Cool Down System #3	LNG Tank No.3	July 1, 2008	Sept. 5, 2008
Ready For Performance Testing		July 18, 2008	July 18, 2008
Substantial Completion		Sept 2, 2008	Nov. 8, 2008
Guaranteed Substantial Completion	1355 days after NTP	Nov. 8, 2008	Dec. 20, 2008
Final Completion (EPC Contract)	Max 90 days after SC	Dec. 10, 2008	Feb. 12, 2009
Total TUA Commences	Total TUA Agreement	April 1, 2009	April 1, 2009
Chevron TUA Commences	Chevron TUA	February 1, 2009	July 1, 2009

7.2    Phase 2

Start-up and commissioning of the Phase 2 Expansion facilities are scheduled for the second quarter of 2009 based on an overall construction duration of 36 months from an Effective Date of July 26, 2006. While this duration would be considered overly optimistic for a new grass-roots facility, in Stone & Webster Consultants’ opinion, it is aggressive but achievable for the Phase 2 Stage 1 Expansion Project, recognizing that the commercial negotiations and design for the major equipment has already been concluded. This notwithstanding, the construction period for the LNG tanks does not contain excessive float and is not overly generous. Sabine and Bechtel will develop a rigorous, logic-linked, Critical Path Method (“CPM”) control schedule within 120 days after NTP. The CPM schedule will allow detailed planning of tie-ins to the Phase 1 facilities and evaluation of access to the site by all parties, including the two export pipeline projects.

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8.0    ENVIRONMENTAL RISKS

Stone & Webster Consultants has reviewed the environmental and regulatory information provided to us by Sabine pertaining to the Phase 2 Expansion, most of which is contained in Sabine’s FERC application. FERC has issued its permit to construct the Phase 2 Expansion. In Stone & Webster Consultants’ opinion, Sabine should be able to obtain the requisite supplementary permits and other regulatory authorizations for the Phase 2 Expansion Project without significant impacts upon either the Phase 1 Project or to the Phase 2 Expansion Project costs or schedule. The expanded facilities will comply with the Equator Principles.

9.0    OPERATIONS & MAINTENANCE PROGRAMS

9.1    Expanded Terminal O&M Costs

During the Phase 2 due diligence, Stone & Webster Consultants and Sabine mutually agreed on an operations and maintenance budget for the expanded, Phase 1 plus Phase 2 LNG Terminal, which is summarized in Table 9.1-1. These O&M Expenses were duplicated in the original due diligence Financial Models. The entries reflect those costs and expenses expected during the first full TUA Contract Year of operations, 2010.

Table 9.1-1

LNG Terminal O&M Expenses

Contract Year 2010

O&M Expense Description	2,000 MMscfd US$ Million	4,000 MMscfd US$ Million
Operations, Maintenance & Contract Labor Costs	10.0	10.0
Other Fixed Operations and Maintenance Costs	14.5	15.2
Subtotal Fixed O&M Costs	24.5	25.2
Fixed Opex Contingency Allowance @ 2.5 percent	0.6	0.6
Total Annual Fixed O&M Costs	25.1	25.8
Annual G&A Costs (Sabine Management & O&M Agreements)	8.3	8.3
Annual GE Power Generation Long-term Maintenance Expenses	3.2	4.6
Total Operations & Maintenance Expenses for Year 2010	36.6	38.7

9.2    Terminal Operational Issues

Based upon all information available, Lanier, an outside marine consultant, concluded in its Marine Traffic Study that the infrastructure of the Sabine-Neches Waterway, coupled with projected staffing increases by the Sabine Pilots Association, would be adequate to handle all of the ship traffic increases projected over the next ten years, including the addition of the three new LNG terminals currently planned by other developers along the Sabine-Neches Waterway. Stone & Webster Consultants concurs with this assessment.

The Phase 1 due diligence effort and the two primary TUAs were based on the assumption that Sabine would receive LNG deliveries by carriers averaging 140,000 cubic meters in size. In Stone & Webster Consultants’ opinion, an average unloading time of 30 hours per LNG carrier is sufficient. This unloading time is supported by shipping simulation study results obtained from software provided to Sabine by an outside shipping consultant. This unloading time results in a total unloading time of 14,160 hours shared between the two berths, which in turn results in 2,880 hours of slack time between the two berths. This is quite reasonable, assuming the average LNG carrier size is 140,000 cubic meters. However, the bulk of the current LNG carrier fleet ranges between 125,000 and 140,000 cubic meters in size. Assuming half of the deliveries were to arrive by 125,000

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cubic meter carriers and half by 140,000 carriers, the total number of deliveries would be approximately 500. Assuming the same unloading time of 30 hours each results in a cumulative unloading time of 15,000 hours. The available slack time for this scenario would be 2,040 hours for a utilization percentage of 88 percent, which is also acceptable. Therefore, in Stone & Webster Consultants’ opinion, the marine unloading facilities as currently designed are more than adequate to support the 2,000 MMscfd of capacity held by the two primary TUA Customers. The facilities also appear to be adequate to support the Sabine Pass LNG Terminal expansion to its peak export capacity 4,000 MMscfd, given that a number of recently ordered LNG carriers are around the 250,000 cubic meter capacity for which the marine terminal is designed.

Sabine’s plan calls for up to fifteen of the pump/vaporizer tandem units to operate at peak capacity, with at least one unit remaining idle as a spare. However, only twelve SCVs are required to meet the combined average demand of the two primary TUA Customers, or 2,000 MMscfd.

In Stone & Webster Consultant’s opinion, one single spare vaporization tandem unit is insufficient to claim a continuous vaporization capacity of 4,000 MMscfd of gas for the expanded facilities. Sabine has not yet commissioned a comprehensive RAM analysis to determine the expected overall availability of the expanded facilities. Therefore, Stone & Webster Consultants determined its own estimate of the availability of the expanded facilities to be a sustained export capacity of approximately 3,500 to 3,600 MMscfd, corresponding to 20 of 24 installed SCVs in operation. Therefore, in Stone & Webster Consultants’ opinion, Sabine will be able to demonstrate the necessary performance level to service the two primary TUA Customers.

Stone & Webster Consultants is of the opinion that the addition of the fourth power generation unit will cover the power consumption requirements of the Phase 2 Stage 1 Expansion Project, such that three units will cover operations with the fourth unit as a stand-by spare. In Stone & Webster Consultants’ opinion, the proposed power generation facilities for the Phase 2 Expansion Project will provide a reliable system that will meet all potential Project performance expectations.

The responsibility for providing pipeline interconnections between the terminal and the existing export natural gas pipeline grid system rests solely with each of the respective Customers of the Sabine Pass LNG Terminal. CSPP has received FERC authorization to construct the CSPP pipeline with an authorized capacity of 2,600 MMscfd. However, Total and Chevron both have indicated that they instead plan to export gas via a new KMLP pipeline, and they are responsible for ensuring that the KMLP will be operational when the two primary TUAs commence operations. CSPP has executed a contract with Willbros Group, Inc. to have the CSPP installed and ready for service by the end of July, 2007. Timely completion of this pipeline is essential to achievement of the Target Bonus Date as this pipeline will deliver the natural gas fuel for the power generation units, which must be fully operational in early September. The scheduled Target Bonus Date for the Phase 1 Sabine Pass LNG Terminal Project is April 3, 2008, so the CSPP should be available to the Project in sufficient time for commissioning and testing under the Bechtel EPC Contract for EPC Contract completion and testing of the Phase 1 Project.

Stone & Webster Consultants has reviewed the proposed OPEX for the combined Phase 1 and Phase 2 Stage 1 facilities. In our opinion, a reasonable level of OPEX has been established by Sabine for the expanded terminal.

10.0    CONTRACTS

10.1    TUAs

Stone & Webster Consultants has reviewed the Total and Chevron TUAs that form the financial foundation of the Project, the respective executed TUA-associated Omnibus Agreements and the executed EPC Contract for Phase 1, dated December 18, 2004.

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Under each of the TUAs, the fees to be paid to Sabine include a Fixed Component Fee, set at US$0.28 per MMBtu of LNG received and is fixed for the 20-year term of the TUA. The FOC Component Fee, designed to partially reimburse Sabine for fixed operating costs, is set initially at US$0.04 per MMBtu, but it is subject to escalation according to the U.S. Consumer Price Index. Also, Sabine is entitled to 2.0 percent of the LNG received for internal terminal energy consumption, primarily for vaporizer and power generation fuel. Stone & Webster Consultants confirms that this should be ample to cover the anticipated consumption. All third-party marine terminal expenses (tug boats and line service boats, etc.) can be passed through 100 percent to the Customers, and the Customers are also obligated to pay a portion of the terminal taxes in addition to the fixed fees. Overall, in Stone & Webster Consultants’ opinion, the TUA fee structure is favorable to the Sponsor, in that payment is due in general terms regardless of terminal throughput, with little risk in terms of Force Majeure and Termination. .

An Omnibus Agreement forms an addendum to each TUA, and provides in each case for early payments, termed Capacity Reservation Fees, of the Fixed Component of the Reservation Fee. These provisions call for Total and Chevron to make US$20.0 million payments to the Sponsor that will be recouped through a monthly reduction in the Fixed Component Fee equal to US$166,667 per month (US$2 million per annum for each) for the first ten years of primary TUA operations.

10.2     Phase 1 EPC Contract

Stone & Webster Consultants reviewed the executed EPC Contract, including the Attachments and Schedules. In our opinion, the EPC Contract generally conforms to the structure, format, and content of basic engineering, procurement and construction contracts utilized for the design and construction of facilities of this type.

The Contractor must maintain a Letter of Credit, valued at ten percent of the Contract Price. Upon achievement of Substantial Completion, the value is reduced to five percent, and the LOC is retired completely at the end of the Defects Correction Period, which ends eighteen months following Substantial Completion. These provisions, in general, provide favorable protection against EPC Contractor non-performance during the construction and warranty periods.

As noted previously, the current EPC Contract schedule is based on a 44-month duration, which Stone & Webster Consultants considered to be reasonable. Most schedules for similar facilities range from 37 to 45 months. Even though the Contract provides for Delay Liquidated Damages of up to 10 percent of the Contract Price, robust for a facility of this type, Stone & Webster Consultants sees little likelihood that Delay Liquidated Damages will require enforcement. Performance Liquidated Damages are specified with a maximum liability of up to 10 percent of the Contract Price for Sendout Rate Performance deficiency and up to two percent for Ship Unloading Time deficiency. The aggregate Performance Liquidated Damages are limited to 10 percent. Thus the Contractor is obligated for a maximum Liquidated Damages liability of 20 percent of the Contract Price.

Total Phase 1 EPC Contract maximum liability is limited to 30 percent; however, the Contractor is obligated for much higher liability in the requirement to demonstrate operational capability of all facilities prior to formal Performance Testing, all of which, taken together, constitute favorable protection. Overall, Stone & Webster considers that the terms of the EPC Contract are reasonable and properly place the responsibility for the timely completion and technical performance of the Project on the general EPC Contractor.

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20. Indemnification of Directors and Officers

Section 17-108 of the Delaware Revised Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever. The fifth amended and restated agreement of limited partnership of Sabine Pass LNG, L.P. provides that Sabine Pass LNG, L.P. will exculpate and indemnify (including advancement of all defense expenses in the event of threatened or asserted claims) its general partner, Sabine Pass LNG-GP, Inc. (and any affiliate, officer, director, partner, employee, trustee and agent of the general partner) to the fullest extent permitted by law; provided, however, that Sabine Pass LNG, L.P. shall not exculpate or indemnify the general partner for conduct constituting gross negligence or willful misconduct.

Item 21. Exhibit and Financial Statement Schedules

(a) Exhibits

Exhibit No.	Description
1.1	Purchase Agreement, dated as of November 1, 2006, by and between Sabine Pass LNG, L.P. and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.1 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 3, 2006).
3.1+	Certificate of Limited Partnership of Sabine Pass LNG, L.P.
3.2+	Fifth Amended and Restated Agreement of Limited Partnership of Sabine Pass LNG, L.P., dated November 9, 2006.
4.1	Indenture, dated as of November 9, 2006, by and between Sabine Pass LNG, L.P., as issuer, and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.1 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
4.2	Registration Rights Agreement, dated as of November 9, 2006, by and among Sabine Pass LNG, L.P. and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.4 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
4.3	Form of 7 1/4% Senior Secured Note due 2013 (included as Exhibit A1 to Exhibit 4.1 above).
4.4	Form of 7 1/2% Senior Secured Note due 2016 (included as Exhibit A1 to Exhibit 4.1 above).
4.5+	Form of general partner interest certificate.
4.6+	Form of limited partner interest certificate.
5.1+	Opinion of Andrews Kurth LLP regarding the validity of the notes.
10.1	Collateral Trust Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New York, as collateral trustee, Sabine Pass LNG-GP, Inc. and Sabine Pass LNG-LP, LLC (incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.2	Amended and Restated Parity Lien Security Agreement, dated November 9, 2006, by and between Sabine Pass LNG, L.P. and The Bank of New York, as collateral trustee (incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).

II-1

Exhibit No.	Description
10.3	Third Amended and Restated Multiple Indebtedness Mortgage, Assignment of Rents and Leases and Security Agreement, dated November 9, 2006, between the Sabine Pass LNG, L.P. and The Bank of New York, as collateral trustee (incorporated by reference to Exhibit 10.3 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.4	Amended and Restated Parity Lien Pledge Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., Sabine Pass LNG-GP, Inc., Sabine Pass LNG-LP, LLC and The Bank of New York, as collateral trustee (incorporated by reference to Exhibit 10.4 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.5	Security Deposit Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New York, as collateral trustee, and The Bank of New York, as depositary agent (incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.6	State Tax Sharing Agreement, dated November 9, 2006, by and between Cheniere Energy, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.9 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.7	Amended and Restated Terminal Use Agreement, dated November 9, 2006, by and between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.6 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.8	Guarantee Agreement, dated as of November 9, 2006, by Cheniere Energy, Inc. in favor of Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.7 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.9	Letter Agreement, dated November 9, 2006, by and among Cheniere Marketing, Inc., Cheniere LNG, Inc. and Sabine Pass LNG, L.P. in favor of Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.8 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.10	LNG Terminal Use Agreement, dated November 8, 2004, by and between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.4 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004).
10.11	Omnibus Agreement, dated November 8, 2004, by and between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004).
10.12+	Guaranty Agreement, dated as of December 15, 2004, from ChevronTexaco Corporation to Sabine Pass LNG, L.P.
10.13	LNG Terminal Use Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004).
10.14	Amendment of LNG Terminal Use Agreement, dated January 24, 2005, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.40 to Cheniere Energy, Inc.’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 10, 2005).
10.15	Omnibus Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004).

II-2

Exhibit No.	Description
10.16	Guaranty, dated as of November 9, 2004, by Total S.A. in favor of Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.3 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004).
10.17	Operation and Maintenance Agreement, dated February 25, 2005, between Sabine Pass LNG, L.P. and Cheniere LNG O&M Services, L.P. (incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on March 2, 2005).
10.18	Management Services Agreement, dated February 25, 2005, between Sabine Pass LNG-GP, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.6 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on March 2, 2005).
10.19	Lump Sum Turnkey Engineering, Procurement and Construction Agreement, dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 20, 2004).
10.20	Change Orders 1 through 27 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004 between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.15 to Cheniere Energy, Inc.’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 3, 2006).
10.21	Change Orders 28, 29 and 31 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004 between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.4 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 5, 2006).
10.22	Change Orders 30, 32 and 33 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004 between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.10 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 4, 2006).
10.23	Change Orders 34, 35, 36, 37 and 38 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2006).
10.24	Agreement for Engineering, Procurement, Construction and Management of Construction Services for the Sabine Phase 2 Receiving, Storage and Regasification Terminal Expansion, dated July 21, 2006, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.7 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 4, 2006).
10.25	Change Order 1 to Agreement for Engineering, Procurement, Construction and Management of Construction Services for the Sabine Phase 2 Receiving, Storage and Regasification Terminal Expansion, dated July 21, 2006, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2006).
10.26	Engineer, Procure and Construct (EPC) LNG Tank Contract, dated July 21, 2006, among Sabine Pass LNG, L.P., Zachry Construction Corporation and Diamond LNG LLC (incorporated by reference to Exhibit 10.8 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 4, 2006).

II-3

Exhibit No.	Description
10.27	Engineer, Procure and Construct (EPC) LNG Unit Rate Soil Contract, dated July 21, 2006, between Sabine Pass LNG, L.P. and Remedial Construction Services, L.P. (incorporated by reference to Exhibit 10.9 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 4, 2006).
10.28+	Amendment to LNG Terminal Use Agreement, dated December 1, 2005, by and between Chevron U.S.A., Inc. and Sabine Pass LNG, L.P.
10.29+	Letter regarding Assumption and Adoption of Obligations under Settlement and Purchase Agreement, dated May 9, 2005, and Indemnification Agreement, dated May 9, 2005, by Cheniere Energy, Inc.
10.30	Change Order 39 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.34 to Cheniere Energy Partners, L.P.’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on December 21, 2006).
10.31+	Change Order 40 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation.
10.32	Settlement and Purchase Agreement, dated and effective as of June 14, 2001, by and between Cheniere Energy, Inc., CXY Corporation, Crest Energy, L.L.C., Crest Investment Company and Freeport LNG Terminal, LLC, and two related letter agreements, each dated February 27, 2003 (incorporated by reference to Exhibit 10.37 to Cheniere Energy Partners, L.P.’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on January 25, 2007).
10.33	Change Order 41 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.36 to Cheniere Energy Partners, L.P.’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on March 2, 2007).
10.34+	Change Orders 42 and 43 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation.
10.35	Change Orders 44 and 45 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2007).
10.36	Letter Agreement, dated May 8, 2007, between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.8 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2007), and Form of LNG Terminal Use Agreement between J & S Cheniere S.A. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit B of Exhibit 8.2(a) of Exhibit 10.8 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2007).
12.1*	Statement regarding computation of ratio of earnings to fixed charges for the period from October 20, 2003 (inception) to December 31, 2003, for the years ended December 31, 2004, 2005 and 2006, for the three months ended March 31, 2007 and 2006 and for the period from October 20, 2003 (inception) to March 31, 2007.
16.1+	Consent letter of UHY LLP to change in certifying accountant.
23.1*	Consent of UHY LLP.
23.2+	Consent of Andrews Kurth LLP (included in Exhibit 5.1).
23.3*	Consent of Stone & Webster Management Consultants, Inc.
24.1	Powers of Attorney (included in signature pages).

II-4

Exhibit No.	Description
25.1+	Form T-1 Statement of Eligibility and Qualification under the Trust Indenture Act of 1939 of The Bank of New York, to act as trustee under the Indenture.
99.1+	Form of Letter of Transmittal.
99.2+	Form of Guidelines for Certification of Taxpayer Identification Number on Substitute Form W-9.
99.3+	Form of Notice of Guaranteed Delivery.
99.4+	Form of Letter to Registered Holders and DTC Participants.
99.5+	Instructions to Registered Holder or DTC Participant.
99.6+	Form of Letter to Clients.

* Filed herewith

+ Previously filed

Item 22. Undertakings

(a) The undersigned Registrant hereby undertakes:

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Securities and Exchange Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initialbona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(4) That, for the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as

II-5

to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(b) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(c) The undersigned hereby undertake to respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11 or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the date of the registration statement through the date of responding to the request.

(d) The undersigned hereby undertake to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

II-6

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on May 29, 2007.

SABINE PASS LNG, L.P.
By:	Sabine Pass LNG-GP, Inc., its general partner
By:	/s/    DON A. TURKLESON
Name:	Don A. Turkleson
Title:	Chief Financial Officer

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons on behalf of the general partner of the Registrant in the capacities and on the dates indicated.

Signature	Title	Date
* Charif Souki	Director	May 29, 2007
* Stanley C. Horton	Chief Executive Officer and Director (Principal Executive Officer)	May 29, 2007
/s/    DON A. TURKLESON         Don A. Turkleson	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	May 29, 2007
* Victor Duva	Director	May 29, 2007

* /s/  DON A. TURKLESON         Don A. Turkleson Attorney-in-Fact

II-7

EXHIBIT INDEX

Exhibit No.	Description
1.1	Purchase Agreement, dated as of November 1, 2006, by and between Sabine Pass LNG, L.P. and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.1 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 3, 2006).
3.1+	Certificate of Limited Partnership of Sabine Pass LNG, L.P.
3.2+	Fifth Amended and Restated Agreement of Limited Partnership of Sabine Pass LNG, L.P., dated November 9, 2006.
4.1	Indenture, dated as of November 9, 2006, by and between Sabine Pass LNG, L.P., as issuer, and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.1 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
4.2	Registration Rights Agreement, dated as of November 9, 2006, by and among Sabine Pass LNG, L.P. and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.4 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
4.3	Form of 7 1/4% Senior Secured Note due 2013 (included as Exhibit A1 to Exhibit 4.1 above).
4.4	Form of 7 1/2% Senior Secured Note due 2016 (included as Exhibit A1 to Exhibit 4.1 above).
4.5+	Form of general partner interest certificate.
4.6+	Form of limited partner interest certificate.
5.1+	Opinion of Andrews Kurth LLP regarding the validity of the notes.
10.1	Collateral Trust Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New York, as collateral trustee, Sabine Pass LNG-GP, Inc. and Sabine Pass LNG-LP, LLC (incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.2	Amended and Restated Parity Lien Security Agreement, dated November 9, 2006, by and between Sabine Pass LNG, L.P. and The Bank of New York, as collateral trustee (incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.3	Third Amended and Restated Multiple Indebtedness Mortgage, Assignment of Rents and Leases and Security Agreement, dated November 9, 2006, between the Sabine Pass LNG, L.P. and The Bank of New York, as collateral trustee (incorporated by reference to Exhibit 10.3 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.4	Amended and Restated Parity Lien Pledge Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., Sabine Pass LNG-GP, Inc., Sabine Pass LNG-LP, LLC and The Bank of New York, as collateral trustee (incorporated by reference to Exhibit 10.4 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.5	Security Deposit Agreement, dated November 9, 2006, by and among Sabine Pass LNG, L.P., The Bank of New York, as collateral trustee, and The Bank of New York, as depositary agent (incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.6	State Tax Sharing Agreement, dated November 9, 2006, by and between Cheniere Energy, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.9 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).

Exhibit No.	Description
10.7	Amended and Restated Terminal Use Agreement, dated November 9, 2006, by and between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.6 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.8	Guarantee Agreement, dated as of November 9, 2006, by Cheniere Energy, Inc. in favor of Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.7 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.9	Letter Agreement, dated November 9, 2006, by and among Cheniere Marketing, Inc., Cheniere LNG, Inc. and Sabine Pass LNG, L.P. in favor of Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.8 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on November 16, 2006).
10.10	LNG Terminal Use Agreement, dated November 8, 2004, by and between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.4 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004).
10.11	Omnibus Agreement, dated November 8, 2004, by and between Chevron U.S.A. Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004).
10.12+	Guaranty Agreement, dated as of December 15, 2004, from ChevronTexaco Corporation to Sabine Pass LNG, L.P.
10.13	LNG Terminal Use Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004).
10.14	Amendment of LNG Terminal Use Agreement, dated January 24, 2005, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.40 to Cheniere Energy, Inc.’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 10, 2005).
10.15	Omnibus Agreement, dated September 2, 2004, by and between Total LNG USA, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004).
10.16	Guaranty, dated as of November 9, 2004, by Total S.A. in favor of Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.3 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 15, 2004).
10.17	Operation and Maintenance Agreement, dated February 25, 2005, between Sabine Pass LNG, L.P. and Cheniere LNG O&M Services, L.P. (incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on March 2, 2005).
10.18	Management Services Agreement, dated February 25, 2005, between Sabine Pass LNG-GP, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.6 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on March 2, 2005).
10.19	Lump Sum Turnkey Engineering, Procurement and Construction Agreement, dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.’s Current Report on Form 8-K (SEC File No. 001-16383), filed on December 20, 2004).
10.20	Change Orders 1 through 27 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004 between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.15 to Cheniere Energy, Inc.’s Annual Report on Form 10-K (SEC File No. 001-16383), filed on March 3, 2006).

Exhibit No.	Description
10.21	Change Orders 28, 29 and 31 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004 between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.4 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 5, 2006).
10.22	Change Orders 30, 32 and 33 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004 between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.10 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 4, 2006).
10.23	Change Orders 34, 35, 36, 37 and 38 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.1 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2006).
10.24	Agreement for Engineering, Procurement, Construction and Management of Construction Services for the Sabine Phase 2 Receiving, Storage and Regasification Terminal Expansion, dated July 21, 2006, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.7 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 4, 2006).
10.25	Change Order 1 to Agreement for Engineering, Procurement, Construction and Management of Construction Services for the Sabine Phase 2 Receiving, Storage and Regasification Terminal Expansion, dated July 21, 2006, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.2 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on November 6, 2006).
10.26	Engineer, Procure and Construct (EPC) LNG Tank Contract, dated July 21, 2006, among Sabine Pass LNG, L.P., Zachry Construction Corporation and Diamond LNG LLC (incorporated by reference to Exhibit 10.8 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 4, 2006).
10.27	Engineer, Procure and Construct (EPC) LNG Unit Rate Soil Contract, dated July 21, 2006, between Sabine Pass LNG, L.P. and Remedial Construction Services, L.P. (incorporated by reference to Exhibit 10.9 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on August 4, 2006).
10.28+	Amendment to LNG Terminal Use Agreement, dated December 1, 2005, by and between Chevron U.S.A., Inc. and Sabine Pass LNG, L.P.
10.29+	Letter regarding Assumption and Adoption of Obligations under Settlement and Purchase Agreement, dated May 9, 2005, and Indemnification Agreement, dated May 9, 2005, by Cheniere Energy, Inc.
10.30	Change Order 39 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.34 to Cheniere Energy Partners, L.P.’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on December 21, 2006).
10.31+	Change Order 40 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation.
10.32	Settlement and Purchase Agreement dated and effective as of June 14, 2001, by and between Cheniere Energy, Inc., CXY Corporation, Crest Energy, L.L.C., Crest Investment Company and Freeport LNG Terminal, LLC, and two related letter agreements, each dated February 27, 2003 (incorporated by reference to Exhibit 10.37 to Cheniere Energy Partners, L.P.’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on January 25, 2007).

Exhibit No.	Description
10.33	Change Order 41 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.36 to Cheniere Energy Partners, L.P.’s Registration Statement on Form S-1 (SEC File No. 333-139572), filed on March 2, 2007).
10.34+	Change Orders 42 and 43 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation.
10.35	Change Orders 44 and 45 to Lump Sum Turnkey Engineering, Procurement and Construction Agreement dated December 18, 2004, between Sabine Pass LNG, L.P. and Bechtel Corporation (incorporated by reference to Exhibit 10.5 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2007).
10.36	Letter Agreement, dated May 8, 2007, between Cheniere Marketing, Inc. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit 10.8 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2007), and Form of LNG Terminal Use Agreement between J & S Cheniere S.A. and Sabine Pass LNG, L.P. (incorporated by reference to Exhibit B of Exhibit 8.2(a) of Exhibit 10.8 to Cheniere Energy, Inc.’s Quarterly Report on Form 10-Q (SEC File No. 001-16383), filed on May 8, 2007).
12.1*	Statement regarding computation of ratio of earnings to fixed charges for the period from October 20, 2003 (inception) to December 31, 2003, for the years ended December 31, 2004, 2005 and 2006, for the three months ended March 31, 2007 and 2006 and for the period from October 20, 2003 (inception) to March 31, 2007.
16.1+	Consent letter of UHY LLP to change in certifying accountant.
23.1*	Consent of UHY LLP.
23.2+	Consent of Andrews Kurth LLP (included in Exhibit 5.1).
23.3*	Consent of Stone & Webster Management Consultants, Inc.
24.1	Powers of Attorney (included in signature pages).
25.1+	Form T-1 Statement of Eligibility and Qualification under the Trust Indenture Act of 1939 of The Bank of New York, to act as trustee under the Indenture.
99.1+	Form of Letter of Transmittal.
99.2+	Form of Guidelines for Certification of Taxpayer Identification Number on Substitute Form W-9.
99.3+	Form of Notice of Guaranteed Delivery.
99.4+	Form of Letter to Registered Holders and DTC Participants.
99.5+	Instructions to Registered Holder or DTC Participant.
99.6+	Form of Letter to Clients.

* Filed herewith

+ Previously filed