Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

OR

Commission File No. 001-16383

CHENIERE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (713) 659-1361

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  x  No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes  ¨  No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x  No  ¨

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ¨  No  x

The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $1,835,000,000 as of June 30, 2006.

56,027,811 shares of the registrant’s Common Stock were outstanding as of February 20, 2007.

Documents incorporated by reference: The definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) is incorporated by reference into Part III.

Table of Contents

CHENIERE ENERGY, INC.

Index to Form 10-K

i

Table of Contents

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements, other than statements of historical facts, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

These forward-looking statements are often identified by the use of terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this annual report.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in “Risk Factors.” All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements are made as of the date of this annual report.

ii

Table of Contents

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Cheniere Energy, Inc., a Delaware corporation, is a Houston-based company engaged, through its subsidiaries, in the energy business generally. As used in this annual report, the terms “we”, “us” and “our” refer to Cheniere Energy, Inc. and its subsidiaries. We are currently engaged primarily in the business of developing and constructing, and then owning and operating, a network of three onshore LNG receiving terminals, and related natural gas pipelines, along the Gulf Coast of the United States. We are also developing a business to market LNG and natural gas, primarily through our wholly-owned subsidiary, Cheniere Marketing, Inc., or Cheniere Marketing. To a limited extent, we are also engaged in oil and natural gas exploration and development activities in the Gulf of Mexico.

Our common stock has been publicly traded since July 3, 1996 under the name Cheniere Energy, Inc., which is incorporated in Delaware. Our common stock is traded on the American Stock Exchange under the symbol LNG. Our principal executive offices are located at 717 Texas Avenue, Suite 3100, Houston, Texas 77002, and our telephone number is (713) 659-1361. Our internet address is http://www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes, nor is it incorporated by reference into this Form 10-K.

In this annual report, unless the context otherwise requires:

Our business activities are operated in four reporting segments in our financial statements for the years ended December 31, 2006, 2005 and 2004 as required under Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information”:

1

Table of Contents

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

Our Business Strategy

We are pursuing a business strategy with the following primary components:

LNG Receiving Terminal Business

We began developing our LNG receiving terminal business in 1999 and, since then, have been among the first companies to secure sites and commence development of new LNG receiving terminals in North America. We have focused our development efforts on the following three LNG receiving terminal projects: Sabine Pass LNG in western Cameron Parish, Louisiana on the Sabine Pass Channel; Corpus Christi LNG near Corpus Christi, Texas; and Creole Trail LNG at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. Although we currently own 100% interests in each of the three LNG receiving terminals, we anticipate that our interest in the Sabine Pass LNG receiving terminal will decrease to approximately 92% upon completion of Cheniere Energy Partners, L.P.’s proposed initial public offering. Financing for the Sabine Pass LNG receiving terminal has been obtained and construction commenced in March 2005. In addition, we own a 30% interest in a fourth project, Freeport LNG, located on Quintana Island near Freeport, Texas. We retained this interest following the sale of 70% of our interest in 2003 to finance our other activities.

Our LNG Receiving Terminals

Sabine Pass LNG

Development

We are developing the Sabine Pass LNG receiving terminal in western Cameron Parish, Louisiana, on the Sabine Pass Channel. In 2003, we formed Sabine Pass LNG, L.P., or Sabine Pass LNG, to own, develop and

2

Table of Contents

operate the Sabine Pass LNG receiving terminal. We have entered into leases for three tracts of land comprising 853 acres in Cameron Parish, Louisiana for the project site. Phase 1 of the Sabine Pass 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, Sabine Pass LNG received approval from the FERC to increase the regasification capacity of the Sabine Pass LNG receiving terminal from 2.6 Bcf/d to 4.0 Bcf/d by adding up to three additional LNG storage tanks, additional vaporizers and related facilities. This expansion is referred to as Phase 2.

Phase 1

In March 2005, the FERC issued an order authorizing Sabine Pass LNG to commence construction of Phase 1 of the Sabine Pass LNG receiving terminal, subject to certain ongoing conditions. Construction of the Sabine Pass LNG receiving terminal began in March 2005. During the second quarter of 2008, we expect to complete construction and commissioning of the first two tanks, complete related equipment installation and specified checks and tests, and achieve a sustained revaporized natural gas sendout at a significant rate for a preagreed period of time. Sabine Pass LNG expects 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.

The cost to construct Phase 1 of the Sabine Pass 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, Sabine Pass LNG entered into a lump-sum turnkey agreement with Bechtel Corporation, or Bechtel, a major international EPC contractor, which as of February 14, 2007 requires Sabine Pass LNG to pay Bechtel $768.2 million, including change orders agreed to date. 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.

Phase 2

In July 2006, Sabine Pass LNG received authorization from the FERC to commence site preparation construction activities for the Phase 2 expansion of the Sabine Pass LNG receiving terminal, subject to certain ongoing conditions. The first stage of the Phase 2 expansion will include the addition of the fourth and fifth LNG storage tanks, additional vaporizers and related facilities, thereby increasing the total regasification capacity of the Sabine Pass 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 – Stage 1 expansion are expected to commence by April 2009. Sabine Pass LNG expects 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 and an aggregate storage capacity of approximately 16.8 Bcf during the third quarter of 2009.

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 by April 2009, and all of Phase 2 – Stage 1 is expected to be completed during the third quarter of 2009.

Construction Agreements

In December 2004, Sabine Pass LNG entered into a lump-sum turnkey EPC agreement with Bechtel for the construction of Phase 1 of the Sabine Pass LNG receiving terminal pursuant to which Bechtel agreed to provide Sabine Pass LNG with services for the engineering, procurement and construction of the Sabine Pass LNG receiving terminal. Except for certain specified 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 the Sabine Pass LNG receiving terminal in accordance with the requirements of the EPC agreement,

3

Table of Contents

including achieving specified minimum acceptance criteria and performance guarantees. Sabine Pass LNG issued a notice to proceed 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. Sabine Pass LNG 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 February 14, 2007, change orders for $121.3 million had been approved, increasing the total contract price to $768.2 million. 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 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 $425,000 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.

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

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

Sabine Pass LNG 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. In addition, Sabine Pass LNG has the option (to be elected on or before March 31, 2007) for Zachry and Diamond to engineer, procure and construct a sixth LNG storage tank, with the cost and completion date to be agreed upon if the option is exercised. We do not expect to exercise this option. 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.

Sabine Pass LNG 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 – Stage 1 site, unless otherwise set forth in the soil contract. Upon issuing a final notice to proceed in August 2006, Sabine Pass LNG paid Recon an initial payment of approximately $2.9 million. The soil contract price is based on unit rates. Payments under the soil contract will be made based on quantities of work performed at unit rates.

Customers

Sabine Pass LNG has entered into three TUAs, through which Total LNG USA, Inc., or Total, Chevron U.S.A., Inc., or 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

4

Table of Contents

of the Sabine Pass 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 the Sabine Pass LNG receiving terminal (2.6 Bcf/d) will be sufficient to cover Sabine Pass LNG’s obligations under the Total and Chevron TUAs. Cheniere Marketing has reserved all of the remaining 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 Sabine Pass LNG has fulfilled its obligations under the Total and Chevron TUAs.

Total TUA

In September 2004, Sabine Pass LNG entered into a TUA with Total to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG receiving terminal. Sabine Pass LNG has no obligation to provide 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 the Sabine Pass 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 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 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 of force 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 the Sabine Pass 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 Sabine Pass LNG 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 25^th of the month prior to the month in which Sabine Pass LNG provides 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 Sabine Pass LNG is entitled to receive a “retainage” equal to 2% of the LNG delivered for Total’s account, which Sabine Pass LNG will use primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility.

If any governmental authority (i) imposes any taxes on Sabine Pass LNG (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 Sabine Pass LNG’s 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, Sabine Pass LNG expects 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, Sabine Pass LNG will reimburse Total for up to one-half of such amount, not to exceed $3.9 million per year.

Sabine Pass LNG is 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, Sabine Pass LNG has pledged its interest under the TUA to the collateral trustee of the $550 million of 7 ¹/4% Senior Secured

5

Table of Contents

Notes due 2013 and $1,482 million of 7 ¹/2% Senior Secured Notes due 2016, which we refer to as the Sabine Pass LNG notes, issued by Sabine Pass LNG in November 2006 to secure its obligations under the Sabine Pass LNG 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 Sabine Pass LNG’s 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 Sabine Pass LNG.

Total may terminate the TUA if Sabine Pass LNG has declared force majeure with respect to a period that has extended, or is projected to extend, for 18 months, or for reasons not excused by force majeure or Total’s actions, if Sabine Pass LNG:

Sabine Pass LNG may terminate the TUA if:

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.

Sabine Pass LNG 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 Sabine Pass LNG enters into a new TUA with a third party, other than its affiliates, for capacity of 50 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.

Chevron TUA

In November 2004, Sabine Pass LNG entered into a TUA with Chevron to provide berthing for LNG vessels and for the unloading, storage and regasification of LNG at the Sabine Pass LNG receiving terminal. Sabine Pass LNG has 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 the Sabine Pass LNG receiving terminal or the construction of any pipelines to provide such transportation or (iii) the marketing of natural gas. 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%.

6

Table of Contents

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 of force 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 Sabine Pass LNG a fixed monthly fee for this regasification capacity that 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 Sabine Pass LNG is entitled to receive a “retainage” equal to 2% of the LNG delivered for Chevron’s account, which Sabine Pass LNG will use primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. Chevron’s payments under the Chevron TUA are due on the 25^th of the month prior to the month in which Sabine Pass LNG provides 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 Sabine Pass LNG (excluding taxes on revenue or income) with respect to the services provided under the TUA, or the Sabine Pass LNG receiving terminal or (ii) enacts any safety or security related regulation which materially increases Sabine Pass LNG’s costs in relation to the services provided at the Sabine Pass 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, Sabine Pass LNG expects that Chevron’s proportionate share of such taxes and increased regulatory costs will be 25%.

Sabine Pass LNG is 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, Sabine Pass LNG has pledged its interest under the TUA to the collateral trustee of the Sabine Pass LNG notes to secure its obligations under the Sabine Pass LNG 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 Sabine Pass LNG’s 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 Sabine Pass LNG.

Chevron may terminate the TUA if Sabine Pass LNG has declared force majeure with respect to a period that has extended, or is projected to extend, for 18 months, or for reasons not excused by force majeure or Chevron’s actions, if Sabine Pass LNG:

Sabine Pass LNG 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

7

Table of Contents

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.

Cheniere Marketing TUA

In November 2006, Sabine Pass LNG 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 the Sabine Pass LNG receiving terminal. Sabine Pass LNG has 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 the Sabine Pass 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 Sabine Pass LNG 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%. The stipulated maximum LNG reception quantity allocated to Cheniere Marketing is reduced to the extent that the Sabine Pass 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 the Sabine Pass LNG receiving terminal; however, the fees to be paid by Cheniere Marketing under the Cheniere Marketing TUA will not be accordingly adjusted.

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 the Sabine Pass 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. Under the Cheniere Marketing TUA, Cheniere Marketing is required to pay Sabine Pass LNG 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 stipulated maximum annual LNG reception quantity; (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 25^th of the month prior to the month in which Sabine Pass LNG provides services under the Cheniere Marketing TUA. In addition, each month, Sabine Pass LNG is entitled to receive a “retainage” equal to 2% of the LNG delivered for Cheniere Marketing’s account, which Sabine Pass LNG will use primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the 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 Sabine Pass LNG by Cheniere.

If any governmental authority (i) imposes any taxes on Sabine Pass LNG (excluding taxes on revenue or income) with respect to the services provided under the Cheniere Marketing TUA, or the Sabine Pass LNG receiving terminal or (ii) enacts any safety or security related regulation which materially increases Sabine Pass LNG’s costs in relation to the services provided at the Sabine Pass 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 the Sabine Pass LNG receiving terminal’s total capacity. After the Chevron and Total TUAs commence, Sabine Pass LNG expects that Cheniere Marketing’s proportionate share of such taxes and increased regulatory costs will be 50%.

Both Sabine Pass LNG and Cheniere Marketing may assign their 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

8

Table of Contents

Cheniere Marketing TUA’s commercial start date. As permitted by the Cheniere Marketing TUA, Sabine Pass LNG has pledged its interest under the Cheniere Marketing TUA to the collateral trustee under the Sabine Pass LNG notes to secure its obligations under the Sabine Pass LNG 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 Sabine Pass LNG (and including credit standards that will be deemed acceptable).

Cheniere Marketing may terminate the Cheniere Marketing TUA if Sabine Pass LNG has declared force majeure with respect to a period that has extended, or is projected to extend, for 18 months, or for reasons not excused by force majeure or Cheniere Marketing’s actions, if Sabine Pass LNG:

Sabine Pass LNG 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 the Sabine Pass LNG receiving terminal that Sabine Pass LNG is 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 the Sabine Pass 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 the Sabine Pass LNG receiving terminal, which is the date on which the Sabine Pass LNG receiving terminal is projected to have capacity of 2.6 Bcf/d.

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

9

Table of Contents

Corpus Christi LNG

Development

We are also developing the Corpus Christi LNG receiving terminal near Corpus Christi, Texas. We formed Corpus Christi LNG, L.P., or Corpus Christi LNG, in May 2003 to develop the terminal. The Corpus Christi LNG receiving terminal was designed, and permitted by the FERC, with a regasification capacity of 2.6 Bcf/d, three LNG storage tanks with an aggregate LNG storage capacity of 10.1 Bcf and two unloading docks capable of handling the largest LNG carriers currently being operated or built. We estimate that the cost to construct the Corpus Christi LNG receiving terminal will be approximately $650 million to $750 million, before financing costs. This estimate is based in part on negotiations with a major international EPC contractor and is subject to change.

In December 2005, the FERC issued an order authorizing Corpus Christi LNG to commence initial construction of the Corpus Christi LNG receiving terminal, subject to satisfaction of certain conditions specified by the FERC. In order to accelerate the timing of developing the Corpus Christi LNG receiving terminal, Corpus Christi LNG elected in April 2006 to commence preliminary site work and entered into an engineering, procurement and construction services agreement for preliminary work with La Quinta LNG Partners, L.P., or La Quinta. La Quinta is a limited partnership whose general partners are Zachry and AMEC E&C Services, Inc. Under the terms of the agreement, La Quinta has provided Corpus Christi LNG with certain preliminary design, engineering, construction and site preparation work on a reimbursable basis in connection with the Corpus Christi LNG receiving terminal. Such preliminary site work commenced during the second quarter of 2006 and has been substantially completed. We anticipate that payments to be made by Corpus Christi LNG to La Quinta for work performed under the agreement will not exceed $35 million. We will contemplate making a final investment decision to complete construction of the Corpus Christi LNG receiving terminal upon, among other things, achieving acceptable commercial arrangements.

Customers

Cheniere Marketing has entered into a TUA with Corpus Christi LNG for 1.0 Bcf/d of regasification capacity at the Corpus Christi LNG receiving terminal.

Creole Trail LNG

Development

We are also developing an LNG receiving terminal at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. We formed Creole Trail LNG, L.P., or Creole Trail LNG, in December 2004 to develop the terminal. We have options to lease tracts of land comprising 1,463 acres in Cameron Parish, Louisiana for the project site. The Creole Trail LNG receiving terminal was designed, and permitted by the FERC, with a regasification capacity of 3.3 Bcf/d, four LNG storage tanks with an aggregate LNG storage capacity of 13.5 Bcf and two unloading docks capable of handling the largest LNG carriers currently being operated or built. We estimate that the cost to construct the Creole Trail LNG receiving terminal will be approximately $850 million to $950 million, before financing costs. Our cost estimate is preliminary and is subject to change.

In June 2006, the FERC authorized Creole Trail LNG to site, construct and operate the Creole Trail LNG receiving terminal. We will contemplate making a final investment decision to commence construction of the Creole Trail LNG receiving terminal upon, among other things, achieving acceptable commercial arrangements.

Customers

We have not entered into any contracts for the regasification capacity at our proposed Creole Trail LNG receiving terminal.

10

Table of Contents

Other Sites

We continue to evaluate, and may develop, additional sites that we believe may be commercially desirable locations for LNG receiving terminals.

Other LNG Interests—Freeport LNG

We own a 30% limited partner interest in Freeport LNG Development, L.P., or Freeport LNG, which is developing an LNG receiving facility on Quintana Island near Freeport, Texas. The first phase of the project includes regasification capacity of 1.5 Bcf/d, one dock, two LNG storage tanks with an aggregate LNG storage capacity of 6.7 Bcf, and a 9.4-mile, 42-inch diameter pipeline through which natural gas will be transported to customer redelivery points at Stratton Ridge, Texas. We expect that the first phase of the Freeport LNG receiving terminal project will commence operations in the first half of 2008. The proposed second phase of the project includes additional regasification capacity of 2.5 Bcf/d, a second dock, a third LNG storage tank with capacity of 3.3 Bcf and 7.5 Bcf of underground salt cavern gas storage. The FERC has authorized Freeport LNG to commence construction of the proposed second phase of the project.

Freeport LNG has entered into TUAs with three customers: The Dow Chemical Company for approximately 500 MMcf/d of regasification capacity; ConocoPhillips Company for approximately 1.0 Bcf/d of regasification capacity in the first phase and approximately 300 MMcf/d of additional regasification capacity in the proposed second phase; and MC Global Gas Corporation, a wholly-owned subsidiary of Mitsubishi Corporation, for approximately 150 MMcf/d of regasification capacity in the proposed second phase and an option to reserve approximately 100 MMcf/d of additional regasification capacity in the second phase. We believe that Freeport LNG has obtained sufficient financing to fund the first phase of the project and a portion of the proposed second phase; as a result, we do not anticipate that any capital calls will be made upon the limited partners of Freeport LNG in the foreseeable future.

Competition

New supplies to meet North America’s natural gas demand could be developed from a combination of the following sources:

In addition, demand for energy currently met by natural gas could alternatively be met by other energy forms such as coal, hydroelectric, oil, wind, solar and nuclear energy. LNG will face competition from each of these energy sources.

We compete with other companies to be among the first to construct LNG receiving terminals in economically desirable locations. 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. To the extent not already fully contracted, and 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. In addition, as of December 31, 2005, there were 51 LNG receiving terminals in 15 countries and other proposed LNG receiving terminals worldwide with which we will compete to be the most economical delivery point for LNG production for both long-term contracted and spot volumes.

11

Table of Contents

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 LNG receiving terminals. This regulatory burden increases the cost of constructing and operating the LNG receiving terminals, and failure to comply with such laws could result in substantial penalties.

FERC

In order to site and construct our proposed LNG receiving terminals, we must receive and are required to maintain authorization from the FERC under Section 3 of the Natural Gas Act of 1938, or NGA. The FERC permitting process includes:

In addition, orders from the FERC authorizing construction of an LNG receiving terminal are typically subject to specified conditions that must be satisfied throughout the construction, commissioning and operation of terminals. Those conditions require us to:

In addition, throughout the life of our LNG receiving terminals, they will be subject to regular reporting requirements to the FERC and the Department of Transportation regarding the operation and maintenance of the facilities.

Other Federal Governmental Permits, Approvals and Consultations

In addition to the FERC authorization under Section 3 of the NGA, our construction and operation of LNG receiving terminals are 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 terminals 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 terminals will also be subject to local and state laws, rules and regulations.

12

Table of Contents

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 receiving terminal 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 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:

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.

13

Table of Contents

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.

Certain persons have expressed concerns that air emissions from the Sabine Pass LNG receiving terminal, which are allowed under Sabine Pass LNG’s 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 Sabine Pass LNG’s 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.

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 receiving terminal 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.

Natural Gas Pipeline Business

We formed Grand Cheniere Pipeline, LLC, a wholly-owned subsidiary, to develop natural gas pipelines that will provide access to North American natural gas markets for customers of our Sabine Pass, Corpus Christi and Creole Trail LNG receiving terminals. Our pipeline systems will connect with multiple interstate pipelines that provide a means of delivering revaporized natural gas from our LNG receiving terminals to various North American natural gas markets. Our ultimate decisions regarding pipeline connections to our facilities will depend upon future events, including, in particular, customer preferences and general market demand for natural gas from a particular LNG receiving terminal.

Our Proposed Pipelines

Sabine Pass Pipeline

We formed Cheniere Sabine Pass Pipeline, L.P., a wholly-owned subsidiary of Cheniere, to develop a 16-mile, 42-inch diameter interstate natural gas pipeline that is designed to transport 2.6 Bcf/d of regasified LNG, connecting from the Sabine Pass LNG receiving terminal and running easterly along a corridor that will allow for interconnection points with existing interstate and intrastate natural gas pipelines in southwest Louisiana, including interstate pipelines operated by Natural Gas Pipeline Company of America,

14

Table of Contents

Transcontinental Gas Pipe Line Corporation, Tennessee Gas Pipeline Company, Florida Gas Transmission and Bridgeline Holdings, L.P. We expect to install interconnects with these existing pipelines, which will initially allow 1.6 Bcf/d of natural gas to be transported. We will be able to transport additional natural gas from the Sabine Pass LNG receiving terminal upon completion of Phase 1 of the Creole Trail Pipeline, as discussed below, or upon installation of additional interconnected capacity with these existing pipelines.

The FERC issued an order in December 2004 authorizing us to construct, own and operate the Sabine Pass Pipeline, subject to specified conditions that must be satisfied. Preliminary engineering, survey and easement acquisition is nearing completion on the Sabine Pass Pipeline. In February 2006, Cheniere Sabine Pass Pipeline, L.P. entered into an EPC pipeline contract with Willbros Engineers, Inc. for the management, engineering, material procurement, construction and construction management of the Sabine Pass Pipeline. We anticipate commencing construction of the Sabine Pass Pipeline in the second quarter of 2007 with construction completed and the pipeline available for commercial operations in the fourth quarter of 2007.

We estimate that the cost to construct the Sabine Pass Pipeline will be approximately $100 million, before financing costs. This estimate is subject to change due to such items as cost overruns, change orders, delays in construction, increased component and material costs and escalation of labor costs.

Creole Trail Pipeline

We formed Cheniere Creole Trail Pipeline, L.P., a wholly-owned subsidiary of Cheniere, or CCTP, to develop a 137-mile, 42-inch diameter interstate natural gas pipeline. The Creole Trail Pipeline is being constructed in two phases. Phase 1 consists of approximately 78 miles of natural gas pipeline interconnecting with the Sabine Pass Pipeline, running east to the site of the Creole Trail LNG receiving terminal and then north and northeast along a corridor that will allow for interconnection points with existing interstate and intrastate natural gas pipelines in southwest Louisiana, which we believe are currently capable of transporting approximately 4.4 Bcf/d. Phase 2 of the Creole Trail Pipeline consists of approximately 59 miles of natural gas pipeline running from the terminus of Phase 1 east to a terminus near Rayne, Louisiana, along a corridor that will allow for interconnection points with existing interstate and intrastate natural gas pipelines, which we believe are currently capable of transporting approximately 7.2 Bcf/d.

The FERC has issued orders authorizing us to construct, own and operate the Creole Trail Pipeline. These authorizations are subject to specified conditions that must be satisfied. CCTP filed an application with the FERC in November 2006 to amend the order received in June 2006 by modifying the planned dual pipeline to be a single pipeline. In December 2006, the FERC issued an order approving the application and partially vacated the previously authorized capacity, thereby reducing the pipeline to a single pipeline capable of transporting 2.0 Bcf/d. Should market demand for transportation service on the Creole Trail Pipeline increase as a result of the Creole Trail LNG receiving terminal commencing commercial operations, CCTP will seek additional FERC authorization at that time to modify its receipt pattern or to increase its pipeline capacity as necessary to satisfy such demand. Once the Creole Trail LNG receiving terminal becomes operational, the flow of gas on the Creole Trail Pipeline may be modified, with volumes moving both west and north/northeast from the Creole Trail LNG receiving terminal, to accommodate the full sendout requirements of the Creole Trail LNG receiving terminal. The increase in pressure resulting from operation of the Creole Trail LNG receiving terminal, in conjunction with the modified receipt pattern, will enable CCTP to transport up to 3.3 Bcf/d on a long-term basis. Alternatively, CCTP may seek additional FERC authorization to modify the Creole Trail Pipeline via extension, looping or compression addition as dictated by evolving market requirements.

CCTP has issued purchase orders to ILVA, S.p.A. and CPW America Co. for the purchase of all of the pipe needed to construct both Phase 1 and Phase 2 of the Creole Trail Pipeline. In the first quarter of 2007, CCTP entered into construction agreements with Sunland Construction, Inc. and Sheehan Pipe Line Construction Company to construct Phase 1 of the Creole Trail Pipeline. A construction contract is currently under negotiation

15

Table of Contents

for approximately 18 miles of Phase 1 of the Creole Trail Pipeline. We anticipate that construction of Phase 1 of the Creole Trail Pipeline will commence in the second quarter of 2007 and that Phase 1 operations will commence in the second quarter of 2008. Construction contracts for Phase 2 of the Creole Trail Pipeline have not been negotiated.

The total anticipated cost to construct Phase 1 and Phase 2 of the Creole Trail Pipeline is approximately $400 million to $450 million and $200 million to $250 million, respectively, 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 and escalation of labor costs.

Corpus Christi Pipeline

We formed Cheniere Corpus Christi Pipeline, L.P., a wholly-owned subsidiary of Cheniere, to develop a 24-mile, 42-inch interstate natural gas pipeline that is designed to transport 2.6 Bcf/d of regasified LNG, connecting from the Corpus Christi LNG receiving terminal and running northwesterly along a corridor that will allow for interconnection points with interstate and intrastate natural gas transmission pipelines in South Texas, including existing pipelines operated by Texas Eastern Transmission Corporation, Gulf South Pipeline Company, L.P., Gulf Terra Intrastate, L.P. (Channel), Kinder Morgan Tejas Pipeline, L.P., Crosstex CCNG Marketing, Ltd., Transcontinental Gas Pipe Line Corporation, Tennessee Gas Pipeline Company and Natural Gas Pipeline Company of America. We believe these existing pipelines are currently capable of transporting approximately 4.6 Bcf/d.

The FERC issued an order in April 2005 authorizing us to construct, own and operate the Corpus Christi Pipeline, subject to specified conditions that must be satisfied. Construction contracts for the Corpus Christi Pipeline have not been negotiated.

Other Pipelines

We continue to evaluate, and may develop, additional pipelines that we believe may be commercially desirable based on customer preferences and general market demand for natural gas from a particular LNG receiving terminal.

Customers

We offered our pipeline capacity to potential customers through a formal request-for-proposal process, and awarded our marketing affiliate all of the capacity in each of our proposed pipelines. Cheniere Marketing has entered into binding precedent agreements for transportation services on each of these pipelines at the maximum tariff rate for the transport and sale of revaporized natural gas that it derives from its own imported LNG or LNG that it purchases from other importers for sale into North American markets. See “—LNG and Natural Gas Marketing Business” below. Cheniere Marketing’s capacity rights and obligations under the transportation precedent agreements are fully assignable, and we anticipate that unaffiliated customers with whom we enter into TUAs for our LNG receiving terminals will desire to also enter into agreements for the transportation of revaporized gas on our proposed pipelines. Furthermore, we expect that other unaffiliated third-party shippers of domestic natural gas may desire transportation services in our pipelines on at least an interruptible basis.

Competition

Our proposed pipelines will compete with intrastate pipelines in Texas and Louisiana and other interstate pipelines throughout our service territory. The principal elements of competition among pipelines are rates, terms of service, access to supply and flexibility and reliability of service. In addition, the FERC’s continuing efforts to increase competition in the natural gas industry are increasing the natural gas transportation options of a pipeline’s traditional customers.

16

Table of Contents

Our pipelines will face competition from other intrastate and/or interstate pipelines that connect with our LNG receiving terminals. In particular, our Sabine Pass Pipeline and Creole Trail Pipeline will compete with the proposed Kinder Morgan Louisiana Pipeline owned by Kinder Morgan Energy Partners, L.P., or Kinder Morgan. Kinder Morgan has announced that it is building a 3.2 Bcf/d take-away pipeline system from the Sabine Pass LNG receiving terminal. The Kinder Morgan Louisiana Pipeline will consist of two segments: a 137-mile, 2.0 Bcf/d pipeline extending to Evangeline Parish, Louisiana, and interconnecting with 11 interstate pipelines as well as a series of intrastate pipes; and a one-mile, 1.2 Bcf/d pipeline interconnecting with the Natural Gas Pipeline Co. of America system near the Sabine Pass LNG receiving terminal. Total and Chevron have both announced agreements with Kinder Morgan securing 100% of the initial capacity on the Kinder Morgan Louisiana Pipeline for 20 years.

Governmental Regulation

Interstate Natural Gas Pipelines

Under the NGA, the FERC regulates the transportation of natural gas in interstate commerce. Under the FERC’s regulations, “transportation” service includes natural gas storage service. In general, the FERC’s authority to regulate pipelines and the services that they provide includes:

Failure to comply with the NGA can result in the imposition of administrative, civil and criminal remedies, including civil and criminal penalties which were recently increased under the EPAct.

The natural gas industry historically has been heavily regulated. The FERC regulates the transportation rates and terms and conditions of service of interstate natural gas pipelines. See “—Rates” below. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, the FERC may not continue this approach.

We have proposed firm and interruptible transportation services, as well as parking and lending services, for our pipelines based on cost of service rates. Beginning in the mid-1980s, the FERC initiated a number of regulatory changes intended to create a more competitive environment in the natural gas marketplace. Among the most important of these changes were:

17

Table of Contents

In November 2003, the FERC issued a series of orders adopting revised Standards of Conduct (Order No. 2004) that apply uniformly to interstate natural gas pipelines. These Standards of Conduct were designed to govern relationships between the pipeline and any energy affiliate, rather than governing conduct between the pipeline and its marketing affiliate. However, in 2006, Order No. 2004, as applied to natural gas pipelines, was vacated by a federal court, and the FERC issued an interim rule which expressly states that the Standards of Conduct do not govern the relationship between natural gas pipelines and its energy affiliates. Shortly thereafter, the FERC issued a notice of proposed rulemaking, which, among other things, requests comments as to whether the interim rule should be made permanent. The comment period will last approximately two months after which time the FERC will issue a final rule.

Our Sabine Pass Pipeline, Corpus Christi Pipeline and Creole Trail Pipeline will be interstate natural gas pipelines, which will connect our LNG receiving terminals directly to the interstate natural gas pipeline grid. To the extent that we construct and operate interstate natural gas pipelines, we must obtain authorization pursuant to Section 7 of the NGA to construct and operate these pipeline facilities, and the rates that we charge will be subject to the FERC’s regulation under Section 4 of the NGA. Our interstate pipelines will also be subject to the FERC’s open access requirements. The FERC’s exercise of jurisdiction over interstate natural gas pipelines is substantially broader than its exercise of jurisdiction over LNG receiving terminals and would continue as long as these pipelines are operated in interstate commerce.

Pipeline Safety

Louisiana and Texas administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal remedies.

The Pipeline Safety Improvement Act of 2002, or PSIA, which is administered by the U.S. Department of Transportation Office of Pipeline Safety governs the areas of testing, education, training and communication. The PSIA requires pipeline companies to perform integrity tests on natural gas transmission pipelines that exist in high population density areas designated as “high consequence areas.” Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. In December 2003, the Department of Transportation issued a Final Rule that became effective January 14, 2004, requiring pipeline operators to develop integrity management programs for gas transportation pipelines. The Final Rule requires pipeline operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline, as necessary; and implement preventive and mitigation actions. This rule incorporates the requirements of the PSIA.

Energy Policy Act of 2005

The EPAct contains numerous provisions relevant to the natural gas industry and to interstate pipelines. See “—LNG Receiving Terminal Business—Governmental Regulation—Energy Policy Act of 2005.”

18

Table of Contents

Rates

Under the NGA, rates charged for the interstate transportation of natural gas must be just and reasonable and not unduly discriminatory. Amounts collected by the pipeline that the FERC finds unlawful are subject to refund with interest.

Environmental Regulation

Our natural gas pipeline business will be subject to the same federal, state and local laws and regulations relating to the protection of the environment that are applicable to our LNG receiving terminals. See “—LNG Receiving Terminal Business—Governmental Regulation—Environmental Regulation” above.

LNG and Natural Gas Marketing Business

We are in the early stages of developing our LNG and natural gas marketing business. Cheniere Marketing has entered into a TUA with each of the Sabine Pass and Corpus Christi LNG receiving terminals. Cheniere Marketing anticipates entering into long-term agreements for the purchase of LNG from foreign suppliers and then selling revaporized natural gas into North American markets. We intend to purchase LNG from foreign suppliers, arrange the transportation of LNG to our network of LNG receiving terminals, utilize Cheniere Marketing’s revaporization capacity at our LNG receiving terminals to revaporize imported LNG, arrange the transportation of revaporized natural gas through our pipelines and other interconnected pipelines, and sell natural gas to buyers in the North American market. Alternatively, we may purchase LNG from foreign suppliers and sell the LNG to foreign purchasers if more favorable economic conditions exist in those markets. In order to develop our marketing capability, we are engaging in domestic natural gas purchase and sale, transportation and storage transactions as part of our initial activities.

To engage in the foregoing commercial activities, Cheniere Marketing has entered into, or intends to enter into, various commercial transactions. These transactions include master natural gas sales contracts, generally using contracts promulgated by the North American Energy Standards Board, or the NAESB contracts; short-term natural gas transportation contracts with various domestic transporters, including parking and loan agreements; financial derivatives agreements, generally using ISDA form contracts promulgated by the International Swap Dealers Association; and futures brokerage and clearing agreements with Calyon Financial and Man Financial, Inc. Our marketing activities will also include the use of derivative transactions in order to take market positions or manage and hedge exposure to price, volume, timing, location, quality and credit risk associated with the marketing of LNG and natural gas. We have developed risk management policies, procedures and systems, which are reviewed regularly, to assist us in controlling and managing our marketing activities.

We have committed $40 million initially to our marketing and trading activities, in addition to overhead costs and natural gas storage charges. We expect that our LNG and natural gas marketing business will have additional capital requirements as its activities expand, which we plan to provide from our available cash or secure from third parties. Lack of access to capital resources could limit the activities of our LNG and natural gas marketing business in the future.

Concurrently with making any commitments to purchase LNG as described above, we expect that Cheniere Marketing would enter into substantially corresponding agreements for the sale of the revaporized gas into the North American market. Although we are actively seeking foreign sources of LNG and domestic buyers of revaporized natural gas for such potential LNG supplies, we currently have no agreements for either (other than the PPM Energy agreement discussed below and the NAESB contracts), and we may not be able to obtain any such long-term agreements on terms acceptable to us, or at all. Credit support will be required by certain counterparties to the above-referenced transactions, including derivatives, which may subject us to additional funding requirements.

19

Table of Contents

Capacity Agreements

In 2006, Cheniere Marketing entered into TUAs for 2.0 Bcf/d and 1.0 Bcf/d of regasification capacity at the Sabine Pass and Corpus Christi LNG receiving terminals, respectively. See “—LNG Receiving Terminal Business—Our LNG Receiving Terminals—Sabine Pass LNG—Customers—Cheniere Marketing” for a more detailed description of the TUA for the regasification capacity at the Sabine Pass LNG receiving terminal.

We have also entered into a ten-year natural gas storage contract, commencing on April 1, 2008, for natural gas storage services of up to a maximum of 3.0 Bcf at a storage facility in Michigan.

Cheniere Marketing has entered into binding precedent agreements for transportation services on each of the Sabine Pass Pipeline, Creole Trail Pipeline and Corpus Christi Pipeline at the maximum tariff rate for the transport and sale of revaporized natural gas that it derives from its own imported LNG or LNG that it purchases from other importers for sale into North American markets. Cheniere Marketing’s capacity rights and obligations under the transportation precedent agreements are fully assignable, and we anticipate that unaffiliated customers with whom we enter into TUAs for our LNG receiving terminals will desire to also enter into agreements for the transportation of revaporized gas on our proposed pipelines.

Customers

In April 2006, Cheniere Marketing entered into a gas purchase agreement with PPM Energy, Inc., or PPM, which is a U.S. subsidiary of Scottish Power plc, a developer and operator of renewable energy in both the United Kingdom and the U.S. Pursuant to the gas purchase agreement, Cheniere Marketing has the right to sell to PPM up to 600,000 MMBtu of natural gas per day and has agreed to initially allocate a portion of the LNG that it procures under a long-term LNG supply agreement to PPM. PPM will be allocated 40% of the first 100,000 MMBtu per day achieved under an LNG supply agreement and 20% after a delivery quantity of 100,000 MMBtu has been achieved. PPM has agreed to buy the natural gas from Cheniere Marketing at a price equal to the sum of (a) 96% of the NYMEX Henry Hub natural gas futures contract price for a delivery month, plus (b) $0.10 per MMBtu. The gas purchase agreement runs for an initial term of 10 years beginning two months after the later to occur of commencement of commercial operations at the Sabine Pass LNG receiving terminal, commencement of commercial operation of the Creole Trail Pipeline with firm service provided to certain principal pipelines, and commencement of commercial delivery of natural gas from the Sabine Pass LNG receiving terminal to the Creole Trail Pipeline. The agreement will extend for a five-year period following the initial term and for a second five-year period following the first extension term unless either party provides written notice of termination to the other party at least 120 days prior to the expiration of the then-current term. Either party may terminate the gas purchase agreement if the initial term has not commenced by June 30, 2010 or Cheniere Marketing has not elected to deliver gas to PPM by October 31, 2010. The parties have various other early termination rights.

Competition

Our LNG purchase efforts will compete with the following for supplies of LNG:

Our natural gas marketing business will compete with the following for the sale of natural gas:

20

Table of Contents

J & S Cheniere

We hold a minority interest in J & S Cheniere S.A., or J & S Cheniere, which was formed to engage in LNG transportation and trading through the utilization and management of charters for two new LNG tankers. The majority interest in J & S Cheniere is held by J & S Energy Holding B.V., or J & S Holding, a Netherlands corporation affiliated with J & S Trading Company, Ltd., an international petroleum trading and marketing company. Pursuant to a shareholders agreement, we identify and assist with LNG-related business opportunities that we determine are appropriate for J & S Cheniere. We are not required to offer any particular business opportunities or funding to J & S Cheniere. All financing of these business opportunities will be provided by J & S Holding should it determine that a business opportunity is appropriate for J & S Cheniere. However, J & S Holding is not required to fund any particular business opportunity. The shareholders agreement gives us the right to purchase additional shares up to a maximum of 50% of the outstanding shares of J & S Cheniere. The shareholders agreement also provides J & S Holding the right to acquire all of our J & S Cheniere shares in the event that we experience a change in control (defined in the shareholders agreement to include a change in a majority of our board, the acquisition of more than 40% of our outstanding common stock other than as approved by our board of directors and a merger or consolidation that results in 50% or less of the surviving entity’s voting securities being owned by the holders of our voting securities immediately prior to such transaction).

In August 2004, J & S Cheniere executed a time charter for an LNG tanker for up to 10 years with Kawasaki Kisen Kaisha, Ltd., or K-Line, to charter a new build, 145,000 cm-capacity LNG tanker being constructed by Kawasaki Shipbuilding Corporation. The tanker is expected to be delivered in the fourth quarter of 2007. In August 2004, J & S Cheniere also executed a time charter agreement for up to 10 years for an LNG tanker with a joint venture company established by K-Line, Shoei Kisen Kaisha, Ltd. and others. The new build, 154,200 cm-capacity LNG tanker is being constructed by Imabari Shipbuilding Co., Ltd. and is expected to be delivered in the second quarter of 2008.

J & S Cheniere entered into an agreement with Cheniere LNG, Inc. in December 2003 under which J & S Cheniere has an option to enter into a TUA reserving up to 200 MMcf/d of capacity at each of our Sabine Pass LNG and Corpus Christi LNG receiving terminals. Following execution of the option agreement, J & S Cheniere paid us an option fee of $1 million. J & S Cheniere may exercise the option as to each LNG receiving terminal by entering into a TUA no later than 60 days after receipt of written notification by us that such LNG receiving terminal has been approved by the FERC and all other approvals and permits have been received which are necessary to begin construction of the terminal. The option agreement provides that any such TUA will provide for: (i) a fee per MMBtu delivered equal to 8% of the then-current price of natural gas at Henry Hub (instead of a capacity reservation fee payable whether or not it uses the terminal); (ii) an initial five-year term, with up to three additional five-year renewal periods upon payment of a $1 million fee for each renewal; and (iii) a minimum of two LNG vessel deliveries per month at the facility. The terms of the TUA contemplated by the J & S Cheniere option agreement have not been negotiated or finalized. We anticipate that definitive arrangements with J & S Cheniere may involve different terms and transaction structures than were contemplated when the option agreement was entered into in December 2003. In November 2006, Cheniere Marketing entered into a letter agreement with Cheniere LNG, Inc. and Sabine Pass LNG pursuant to which Cheniere Marketing has agreed to relinquish up to 200 Mmcf/d of its regasification capacity (and proportionately reduce its fixed monthly fee) under the Cheniere Marketing TUA if required to allow Sabine Pass LNG to satisfy its obligations under a potential TUA with J & S Cheniere.

21

Table of Contents

Governmental Regulation

In 1992 and 1993, the FERC concluded that sellers of short-term or long-term natural gas supplies would not have market power over the sale for resale of natural gas. The FERC established light-handed regulation over sales for resale of natural gas and adopted regulations granting blanket certificates to allow entities selling natural gas to make interstate sales for resale at negotiated rates. In 2003, the FERC amended the blanket marketing certificates to require that all sellers adhere to a code of conduct with respect to natural gas sales. The code of conduct addresses such matters as natural gas withholding, manipulation of market prices, communication of accurate information and record retention.

The EPAct contains provisions intended to prohibit the manipulation of the natural gas markets and to increase the ability of the FERC to enforce and promote compliance with the statutes, orders, rules and regulations that the FERC administers. In 2005, the EPAct amended the NGA to add an anti-manipulation provision. To implement this provision of the EPAct, the FERC issued a final rule in 2006 that makes it unlawful for any entity, in connection with the purchase or sale of natural gas, or the purchase or sale of transportation service under the FERC’s jurisdiction, to (1) use or employ any devise, scheme or artifice to defraud; (2) make any untrue statements of a material fact, or omit to state a material fact needed in order to make a statement not misleading; or (3) engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any entity.

The prices at which we will sell natural gas are not regulated, insofar as the interstate market is concerned and, for the most part, are not subject to state regulation. We are permitted to domestically make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate automatically granted by the FERC. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, under “—Natural Gas Pipeline Business—Governmental Regulation,” the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.

Oil and Gas Exploration and Development Business

Although our focus is primarily on development of LNG-related businesses, we continue to be involved to a limited extent in oil and gas exploration, development and exploitation. Our historical oil and gas exploration activities have existed through active interpretation of our seismic data and generation of prospects, through participation in the drilling of wells, and through farm-out arrangements and back-in interests (a reversionary interest in oil and gas leases reserved by us) whereby the capital costs of such activities are borne primarily by industry partners. Our current oil and gas exploration and development activities have been focused on two areas: the Cameron Project, which covers an area of approximately 230 square miles extending roughly three to five miles on either side of the westernmost 28 miles of Louisiana coastline; and the Offshore Texas Project Area, which covers approximately 6,800 square miles in the shallow waters offshore Texas and the West Cameron Area of offshore Louisiana.

Prospects

Our exploration team generated, captured, sold or caused to be drilled 11 prospects during 2004, 2005 and 2006. We retained interests in the form of overriding royalty interests (a share of the hydrocarbons produced from an oil and gas property, free of the expense of production) and backin working interests (an agreement whereby we retain a reversion right to a working interest in a well at payout but bear none of the cost of drilling the initial well). Our overriding royalty interests range from 0.63% up to 5.0%, and backin working interests range from 15.0% up to 20.0%. We also participated in the drilling of wells with cost-bearing working interests of 5.0% up to 25.0%. In the wells where we participated with a cost-bearing working interest, we also retained an overriding royalty interest prior to payout and a backin working interest after payout. All 11 of the above-mentioned prospects were drilled by our industry partners.

22

Table of Contents

Drilling Activities

During 2004, we did not participate directly in the drilling of any wells; in 2005, we participated directly in the drilling of two wells; and in 2006, we participated directly in the drilling of four wells. Our industry partners drilled two wells, three wells and six wells in 2004, 2005 and 2006, respectively, on prospects that we generated. During 2004, both wells were discoveries; during 2005, one well was a discovery; and during 2006, four wells were discoveries. For the discoveries drilled in the years 2004 through 2006, four of the wells are producing and three are temporarily suspended awaiting development.

At December 31, 2006, we had working interests of 5.0% to 25.0% in four wells and overriding royalty interests (ranging from 0.63% to 5.0%) in sixteen other wells. Of the 20 wells in which we had an interest as of December 31, 2006, three were temporarily suspended awaiting development, nine were productive and eight were shut in waiting for plugging and abandonment. Of the eight wells waiting for plugging, seven were wells in which we had only an overriding royalty interest and therefore, we have no liability for abandonment costs.

Production and Sales

The following table presents certain information with respect to our oil and natural gas production, average sales prices received and average production costs during 2004, 2005 and 2006.

Acreage

The following table sets forth certain information with respect to our developed and undeveloped leased acreage as of December 31, 2006.

23

Table of Contents

Oil and Gas Reserves

All of the information herein regarding estimates of our proved reserves, related future net revenues and PV-10 as of December 31, 2006 is taken from the report generated by Sharp Petroleum Engineering, Inc., an independent petroleum engineer, in accordance with the rules and regulations of the SEC. The independent engineer’s estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data that we provided.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and future amounts and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, geologic success and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, our reserves may be subject to downward or upward revision based upon production history, purchases or sales of properties, results of future development, prevailing oil and gas prices and other factors. Therefore, the present value shown above should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties.

In accordance with SEC guidelines, the estimates of future net revenues from our proved reserves and the present value thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. We may receive amounts different than the estimates for a number of reasons, including changes in prices. See Supplemental Information to Consolidated Financial Statements. Estimates of our proved oil and gas reserves were not filed with or included in reports to any other federal authority or agency other than the SEC during the fiscal year ended December 31, 2006.

Experience

We have built a technical and management team that is experienced in the Gulf of Mexico and in various technical specialties required for our exploration program. The technical staff averages over 30 years of experience exploring for oil and gas in the Gulf Coast. We believe that this experienced team allows us to be very productive in the generation and acquisition of prospects.

Competition and Markets

The availability of a ready market for and the price of any hydrocarbons that we produce will depend on many factors beyond our control, including:

24

Table of Contents

In the past, as a result of excess deliverability of natural gas, many pipeline companies curtailed the amount of natural gas taken from producing wells, shut in some producing wells, significantly reduced gas taken under existing contracts, refused to make payments under applicable take-or-pay provisions and have not contracted for gas available from some newly completed wells.

In addition, the restructuring of the natural gas pipeline industry has eliminated the gas purchasing activity of traditional interstate gas transmission pipeline buyers. Producers of natural gas, therefore, have been required to develop new markets among gas marketing companies, end-users of natural gas and local distribution companies. All of these factors, together with economic factors in the marketing area, generally may affect the supply and/or demand for oil and gas and thus the prices available for sales of oil and gas.

Competition in the industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage. We compete with independent producers of varying sizes, all of which are engaged in the exploration, development and acquisition of producing and non-producing properties.

Governmental Regulation

Our oil and gas exploration, development and related operations are subject to extensive federal, state and local statutes, rules, regulations and other laws. Failure to comply with such laws can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability.

MMS Regulations

We conduct certain activities on federal oil and gas leases which the Minerals Management Service, or MMS, administers. The MMS grants leases through competitive bidding. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to The Outer Continental Shelf Lands Act, or OCSLA. For example, for offshore operations, we must comply with the following MMS requirements:

25

Table of Contents

Bonding and Financial Responsibility Requirements

In connection with our ownership or operation of oil and gas leases, we are required by governmental agencies, including the MMS, to obtain bonding or otherwise demonstrate financial responsibility at varying levels. These bonds may cover such obligations as plugging and abandonment of wells, removal and closure of related exploration and production facilities, and pollution liabilities. The costs of such bonding and financial responsibility requirements can be substantial, and we may not be able to obtain such bonds and/or otherwise demonstrate financial responsibility in all cases.

Regulation of Production

Our oil and gas production operations are subject to state conservation laws and regulations, including:

Such laws may restrict the rate at which the wells in which we have an interest may produce oil or gas, with the result that the amount or timing of our revenues could be adversely affected.

Environmental Regulation

Our oil and gas exploration, development and related operations are subject to the same federal, state and local laws and regulations relating to the protection of the environment that are applicable to our LNG operations. See “—LNG Receiving Terminal Business—Governmental Regulation—Environmental Regulation” above. In addition, our oil and gas exploration, development and related operations are subject to the following regulations.

The disposal of wastes containing Naturally Occurring Radioactive Material, which are commonly generated during oil and gas production, is regulated under state law. Typically, wastes containing naturally occurring radioactive material can be managed on site or disposed of at facilities licensed to receive such waste at costs that are not expected to be material.

The federal Oil Pollution Act of 1990, or OPA, requires owners and operators of facilities that could be the source of an oil spill into waters of the U.S. (a term defined to include rivers, creeks, wetlands and coastal waters) to adopt and implement plans and procedures to prevent any such oil spill. OPA also requires affected facility owners and operators to demonstrate that they have at least $35 million in financial resources to pay the costs of cleaning up an oil spill and to compensate any parties damaged by an oil spill. Such financial assurances may be increased to as much as $150 million if a formal assessment indicates such an increase is warranted.

Financial Information About Segments

During the last three fiscal years, substantially all of our revenues have resulted from our oil and gas exploration and development activities. For information about our segments’ revenues, profits and losses and total assets, see Note 24 of our Notes to Consolidated Financial Statements.

Subsidiaries

Our assets are generally held by or under our operating subsidiaries. We conduct most of our operations through these subsidiaries, including our operations relating to the development of our LNG receiving terminal business, the development of our pipeline business and our marketing business.

Employees

We had 256 full-time employees as of February 1, 2007.

26

Table of Contents

ITEM 1A. RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operation, financial condition and prospects.

Risks Relating to Our Financial Matters

We have not been profitable historically, and we are currently experiencing negative operating cash flow. Our ability to achieve profitability and generate positive operating cash flow in the future is subject to significant uncertainty.

From our inception, we have generally incurred operating losses, and we will likely continue to incur operating losses and experience negative operating cash flow through 2008. We have not yet started the construction of two of our three planned LNG receiving terminals or our pipelines. We do not anticipate that our LNG receiving operations or our three pipelines will generate positive operating cash flow until at least one of our planned LNG receiving terminals is built, which we expect will not be until 2008 at the earliest. Although we may commence operations at our LNG receiving terminals, revenues under any third-party TUA may not commence for up to one year or more after operations at the related facility commence. We will continue to incur significant capital and operating expenditures while we develop our planned LNG receiving terminals and pipelines. We do not anticipate that our current oil and gas exploration activities, which are limited in scope, or advance sales of regasification capacity at our planned LNG receiving terminals will generate sufficient funds to cover these expenditures.

Any delays beyond the expected development periods for our planned LNG receiving terminals or pipelines would prolong, and could increase the level of, our operating losses and negative operating cash flow. Our future liquidity may also be affected by (i) the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and (ii) the anticipated timing of receipt of cash flow under TUAs and other sales of capacity in relation to the incurrence of projected project operating expenses. However, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements. Our ability to generate positive operating cash flow and achieve profitability in the future is dependent on our ability to successfully complete our LNG development projects and market the capacity of our facilities, and our ability to do so is subject to a number of risks, including those discussed below.

Our ability to develop our planned LNG receiving terminals and pipelines is contingent on our ability to obtain funding. If we are unable to do so, we may be unable to implement or complete our business plan, and our business may ultimately be unsuccessful.

As of December 31, 2006, we had $463.0 million in cash and cash equivalents, exclusive of $1.2 billion in restricted cash. We currently estimate that the cost of completing our three LNG receiving terminals will be approximately $3.0 billion, before financing costs, and the cost of constructing our three proposed pipelines will be approximately $800 million to $1 billion. 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 the construction schedules. In addition, the development of our marketing business will require significant credit support funding. To fund all of these development projects, we will have to pursue a variety of sources of funding besides those that we currently have committed or planned, including most, if not all, of the following:

27

Table of Contents

Our ability to obtain these types of financing 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 and such markets’ view of our industry and prospects at such time. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, if at all, even if our development projects are otherwise proceeding on schedule. In addition, our ability to obtain some types of financing may be dependent upon our ability to obtain other types of financing. For example, project-level debt financing is typically contingent upon a significant equity capital contribution from the project sponsor. As a result, even if we are able to identify potential project-level lenders, we may still have to obtain another form of external financing for us to fund an equity capital contribution to the project subsidiary. Any project-level debt financing will also typically be conditioned upon our prior receipt of commitments for a portion of projected regasification capacity under long-term TUAs, and our ability to fund the projects will likely be subject to the achievement of additional milestones in our project financing. A failure to obtain financing at any point in the development process could cause us to delay or fail to complete our business plan, which could cause our business to be unsuccessful.

Even if we are able to obtain financing, the terms required may adversely affect our business.

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

Our substantial indebtedness could adversely affect our ability to operate our business.

As of December 31, 2006, we had approximately $2.4 billion of indebtedness. Our substantial indebtedness could have important consequences, including:

28

Table of Contents

Under some circumstances, our substantial indebtedness and the restrictive covenants contained in our debt agreements may not allow us the flexibility that we need to operate our business in an effective and efficient manner and may prevent us from taking advantage of strategic and financial opportunities that would benefit our business.

Our ability to satisfy our obligations will depend upon our future operating performance. Prevailing economic conditions and financial, business and other factors, many of which are beyond our control, will affect our ability to make payments on our debt obligations. If we are not able to generate sufficient cash from operations to meet our other obligations, we may need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.

We may experience cost overruns and delays in the completion of our proposed LNG receiving terminals and pipelines 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 our proposed LNG receiving terminals and pipelines 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. As of February 14, 2007, change orders for $121.3 million had been approved under the Phase 1 EPC agreement with Bechtel for the Sabine Pass LNG receiving terminal. We do not have any prior experience in constructing LNG receiving terminals, and no LNG receiving terminal has been constructed and placed in service in the United States in almost 25 years, as a result of which there are limited benchmarks against which to compare our estimates.

Furthermore, in order to cover not only increased costs but also the cost of a sixth LNG storage tank that we may be required to construct at the Sabine Pass LNG receiving terminal if requested by Cheniere Marketing under its TUA, we may need to obtain additional funding. If we fail to obtain sufficient funding, our business plan could fail. Our ability to obtain debt or equity financing that may be needed to provide additional funding to cover increased costs will depend, in part, on factors beyond our control, such as the status of various capital and industry markets at the time financing is sought. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, if at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have a material adverse effect on our current or future business, results of operations, financial condition and prospects.

Risks Relating to Our LNG Receiving Terminal Business

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

We are currently constructing the Sabine Pass LNG receiving terminal. We may not complete Phase 1 or Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal, and our other LNG receiving terminals, in a timely

29

Table of Contents

manner, or at all, due to numerous factors, some of which are beyond our control. Factors that could adversely affect our planned completion include:

Our inability to timely complete the Sabine Pass LNG receiving terminal and our other LNG receiving terminals, 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.

We are dependent on Bechtel and other contractors for the successful completion of our LNG receiving terminals.

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 proposed LNG receiving terminals 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:

30

Table of Contents

These risks are heightened for Phase 2 – Stage 1 of the Sabine Pass LNG receiving terminal, which is still in the contracting phase. A substantial number of contracts, such as for performing portions of or supplying materials for Phase 2 – Stage 1, remain to be negotiated for Phase 2 – Stage 1, and we may be unable to reach satisfactory arrangements for these contracts. As a result, the scope, design, timing and cost for Phase 2 – Stage 1 construction are not as well defined as they are for Phase 1 of the Sabine Pass LNG receiving terminal, 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 may provide for liquidated damages, if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable LNG 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 by force majeure events and our insolvency, breach of material obligations not subject to adjustment by change order, or failure to pay undisputed amounts.

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

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

Our LNG receiving terminals must undergo a commissioning process for their 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 terminals, which we have projected will be approximately $157.5 million for the Sabine Pass LNG receiving terminal. 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:

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

31

Table of Contents

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development of our LNG receiving terminals could impede completion of the terminals 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 NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to construct and operate our proposed LNG receiving terminals. Although we have obtained NGA Section 3 authorization to construct and operate our LNG receiving terminals, 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 our proposed LNG receiving terminals, 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.

After our LNG receiving terminals are placed in service, their businesses will involve significant operational risks.

If we are successful in completing our LNG receiving terminals, we will still face risks associated with operating the facilities. These risks will include, but will not be limited to, the following:

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

Our three existing TUAs for regasification capacity at the Sabine Pass LNG receiving terminal provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG receiving terminal, which will be used 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.

The inability to import LNG into the United States could materially adversely affect our customers and our business plans and results of operations if we have to replace TUAs that terminate or expire.

Upon completion of the LNG receiving terminals, our business will be dependent upon the ability of our third-party customers and Cheniere Marketing to import LNG supplies into the United States. Political instability in foreign countries that have supplies of natural gas, or strained relations between such countries and the United States, may impede the willingness or ability of LNG suppliers in such countries to export LNG to the United States. Such foreign suppliers may also be able to negotiate more favorable prices with other LNG customers

32

Table of Contents

around the world than with customers in the United States, thereby reducing the supply of LNG available to be imported into the United States market. Any significant impediment to the ability to import LNG into the United States could have a material adverse affect on our customers 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 our pipelines or the pipelines interconnected with or downstream of our proposed LNG receiving terminals.

Failure of sufficient LNG liquefaction capacity to be constructed worldwide could adversely affect the performance by our customers of their obligations under the TUAs and could reduce our operating revenue and cause us operating losses.

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

If sufficient LNG liquefaction capacity is not constructed, our customers may find it difficult to obtain sufficient utilization of their capacity at our LNG receiving terminals to support their obligations under their TUAs.

A shortage of LNG tankers worldwide could adversely affect our and our potential customers’ ability to import LNG into North America, which could inhibit our growth and cause us operating losses.

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 ability and the ability of potential customers to import LNG into North America. The construction and delivery of additional LNG vessels requires significant capital, and the availability of the vessels could be delayed to our detriment because of:

33

Table of Contents

Failure of imported LNG to become a competitive source of energy in North America could adversely affect our ability to enter into TUAs with customers and our ability to import LNG into North America, which could inhibit our growth and cause us operating losses.

In North America, due mainly to an abundant supply of natural gas, imported LNG has not historically been a major energy source. Our business plan is based, in part, on the belief that LNG can be produced and delivered 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 would further increase the available supply of natural gas at a lower cost than LNG. In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. As a result, LNG may not become a competitive source of energy in North America. The failure of LNG to become a competitive supply alternative to domestic natural gas, oil and other import alternatives could adversely affect our ability to enter into TUAs with customers at the proposed Creole Trail LNG receiving terminal or the proposed Corpus Christi LNG receiving terminal and could impede the ability of Cheniere Marketing to import LNG into North America, which could reduce our operating revenues and cause us operating losses. 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 and able to pay more for LNG, thereby eliminating the supply of LNG available in North American markets. The failure of LNG to become a competitive supply alternative may impede our ability to obtain customers for regasified LNG, which may inhibit our growth and cause us operating losses.

Decreases in the price of natural gas could lead to reduced development of LNG projects worldwide, which could adversely affect our ability to enter into TUAs and natural gas sale contracts with customers, which could inhibit our growth and cause us operating losses.

The development of domestic LNG receiving terminals and LNG projects generally is based on assumptions about the future price of natural gas and the availability of imported LNG. Natural gas prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to any of the following factors:

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

34

Table of Contents

Cyclical changes in the demand for LNG regasification capacity may adversely affect our ability to enter into TUAs and natural gas sale contracts with customers, which could inhibit our growth and cause us operating losses.

The economics of LNG terminal operations could be subject to cyclical swings, reflecting alternating periods of under-supply and over-supply of LNG importation capacity and available natural gas, principally due to the combined impact of several factors, including:

These changes in the economics of LNG terminal operations could materially adversely affect our and our customers’ ability 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 our TUAs terminate or expire, unfavorable economic conditions that affect our customers could, in turn, for similar reasons, reduce our operating revenues and cause us operating losses.

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

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 proposed LNG receiving terminals and, upon commencement of commercial operation, to provide our customers with the highest quality service. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult to attract and retain personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. For example, in the aftermaths of Hurricanes Katrina and Rita, Bechtel and certain subcontractors temporarily experienced a shortage of available skilled labor necessary to meet the requirements of the Sabine Pass LNG receiving terminal 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 the Sabine Pass LNG receiving terminal. Any increase in our operating costs could materially adversely affect our business, results of operations, financial condition and prospects.

We may face competition in the LNG receiving terminal business 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

35

Table of Contents

Corporation, Excelerate Energy, McMoRan Exploration, Occidental Petroleum, Sempra, Suez and other public and private companies have also proposed developing or expanding LNG receiving facilities in North America, both onshore and offshore. Almost all of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to LNG supply than we do. The superior resources that these competitors have available for deployment could allow them to compete successfully against us.

Industry analysts have predicted that if a substantial number of the proposed LNG receiving terminals in North America that have been announced by developers were actually built, there would likely be substantial excess capacity available from such terminals in the future. In addition, our proposed LNG receiving terminals will likely continue to face competition when and if they are completed, including competition from North American sources of natural gas and onshore, offshore and shipboard LNG regasification facilities. Our LNG receiving terminals will also compete with the Freeport LNG receiving terminal that is currently under construction and in which we own a 30% 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 our business, results of operations, financial condition and prospects.

We may have difficulty obtaining enough customers for regasification capacity at our proposed LNG receiving terminals to implement and complete our business plan. We may change our business strategy as to how and when we market our capacity.

Our current marketing strategy calls for us to enter into long-term TUAs for a portion of the regasification capacity at our LNG receiving terminals, including a commitment to pay capacity reservation fees, prior to the commencement of construction of each facility. The portion of our total regasification capacity that we plan to commit under such long-term TUAs has changed in the past and may change in the future for various reasons, including responding to market factors or perceived opportunities that we believe may be available to us. Our ability to obtain project-level financing for each LNG receiving facility may be contingent on our ability to enter into long-term TUAs in advance of the commencement of construction. In addition, we anticipate that we will be able to rely on these capacity reservation fee payments to cover a portion of operating costs prior to commencement of operations at our proposed LNG receiving terminals. As of the date of this filing, we do not have any third-party TUAs in place for either our proposed Corpus Christi LNG receiving terminal or our proposed Creole Trail LNG receiving terminal, nor do we have any third-party contracts in place for the use of our pipelines.

We may experience difficulty attracting additional customers because we are a small, developing company with no operating history in the LNG business. In order to succeed, we must convince additional potential customers, among other things, that we will be able to secure adequate financing for the construction of the LNG receiving terminal sites and natural gas pipelines that we are developing and that they will be approved by appropriate governmental agencies. We may also change our marketing strategy due to our inability to enter into TUAs with additional customers prior to construction and our view regarding future prices, demand and supply of natural gas and regasification capacity. If these marketing efforts are not successful, our business, results of operations, financial condition and prospects could be materially adversely affected.

Our TUAs are subject to termination by our contractual counterparties under certain circumstances, and we are generally dependent on the performance of those counterparties under the TUAs.

Sabine Pass LNG has entered into long-term TUAs with Total, Chevron and Cheniere Marketing. Each of the TUAs contains various termination rights. For example, each counterparty may terminate its TUA if the Sabine Pass LNG receiving terminal experiences a force majeure delay for longer than 18 months, fails to deliver a specified amount of natural gas redelivery nominations or fails to receive or unload a specified number of LNG cargoes. 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

36

Table of Contents

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 ultimately successful in seeking damages from that counterparty or its guarantor for a breach of the TUA.

Risks Relating to Our Pipeline Business

Expanding our business by constructing pipelines subjects us to risks.

The construction of a new pipeline involves numerous regulatory, environmental, political and legal uncertainties beyond our control and requires the expenditure of significant amounts of capital that we will be required to finance through borrowings, through the issuance of additional equity or from operating cash flow. If we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. For instance, if we build a new pipeline, the construction may occur over an extended period of time, and we will not receive any revenues until the pipeline has been completed and customers pay for transportation service on the pipeline. Moreover, we may construct pipelines to capture anticipated future growth in a region in which such growth does not materialize. As a result, our pipelines may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. The success of our pipeline construction project may depend upon the level of LNG import activity in the areas proposed to be serviced by the project as well as our ability to obtain commitments from LNG suppliers and other customers to utilize the newly constructed pipelines.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development of our pipelines would have a detrimental effect on us and our LNG projects.

The design, construction and operation of natural gas pipelines and the transportation of natural gas are all highly regulated activities. FERC approval under Section 7 of the NGA, as well as several other material state governmental and regulatory approvals and permits, is required in order to construct and operate our proposed pipelines. We also have not obtained several other material governmental and regulatory approvals and permits required in order to construct and operate our proposed pipelines, 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 timing of the review and approval process nor can we predict the outcome of the process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any third parties will attempt to interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in the projects. 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.

Our proposed pipelines, including their FERC gas tariffs, will be subject to FERC regulation.

Our FERC tariffs contain pro forma transportation agreements, which must be filed and approved by the FERC. Before we enter into a transportation agreement with a shipper that contains a term that materially deviates from our tariff, we must seek FERC approval. The FERC may approve the material deviation in the transportation agreement; however, in that case, the materially deviating terms must be made available to our other similarly-situated customers. If we fail to seek FERC approval of a transportation agreement that materially deviates from our tariff, or if FERC audits our contracts and finds deviations that appear to be unduly discriminatory, the FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the recently enacted Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation.

37

Table of Contents

The FERC could change its current ratemaking policies, and those changes could have adverse effects on our proposed pipelines.

Any reduction in the capacity of, or the allocations to, interconnecting, third-party pipelines could cause a reduction of volumes transported in our proposed pipelines, which would adversely affect our revenues and cash flow.

We will depend upon third-party pipelines and other facilities that will provide delivery options to and from our proposed pipelines. If any pipeline connection were to become unavailable for volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any permanent interruption at any key pipeline interconnect which caused a material reduction in volumes transported on our proposed pipelines could have a material adverse effect on our business, results of operations and financial condition.

Our pipeline business could be materially adversely affected if we lose the right to situate our proposed pipelines on property owned by third parties.

We do not anticipate owning the land on which our proposed pipelines will be constructed, and we are subject to the possibility of increased costs to obtain and retain necessary land use. We anticipate obtaining the right to construct and operate our pipelines on land owned by third parties for a period of time. If we were to lose these rights or be required to relocate our pipelines, our business could be materially adversely affected.

Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.

The federal Office of Pipeline Safety has issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in what the rule refers to as “high consequence areas” where a leak or rupture could potentially do the most harm. The final rule requires operators to:

We will be required to initiate pipeline integrity testing programs that are intended to assess pipeline integrity. The rule, or an increase in public expectations for pipeline safety, may require additional reporting and more frequent inspection or testing of our proposed pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to penalties and fines.

Because our proposed pipelines will be dependent upon a few customers, including an affiliate, for a significant portion of the revenues anticipated to be generated by our pipeline business, our business may be materially and adversely affected if we lose any one of these customers.

We do not currently have any third-party customers for our pipelines. Customers with whom we enter into TUAs for our LNG receiving terminals may enter into agreements for the transportation of revaporized gas on our proposed pipelines. However, the number of such customers is anticipated to be limited, and we anticipate being substantially dependent on them for a significant percentage of the revenues generated by our pipeline business. In addition, the largest customer of our proposed pipelines is anticipated to be our affiliate, Cheniere

38

Table of Contents

Marketing, which does not have any arrangements for any supplies of LNG or any unconditional commitments from customers for the purchase of natural gas. The loss of any customers, a decline in their creditworthiness, the failure of Cheniere Marketing to obtain LNG or customers for regasified LNG, or a substantial reduction in customers’ shipments on our proposed pipelines could have a material adverse effect on our business, results of operations and financial condition.

Risks Relating to Our LNG and Natural Gas Marketing Business

We are in the early stages of developing our LNG and natural gas marketing business.

We have just recently begun developing our LNG and natural gas marketing business. To date, the business has a limited operating history upon which to evaluate our business strategy or the future prospects of the business. The ability of our LNG and natural gas marketing business to generate revenues in the future will depend upon whether we can successfully develop and implement our business strategy and make the transition from a development stage business to an operating business. We may encounter many expenses, delays, problems and difficulties that we have not anticipated and for which we have not planned in developing and operating our LNG and natural gas marketing business.

Our use of hedging arrangements may adversely affect our future results of operations or liquidity.

To reduce our exposure to fluctuations in the price, volume, timing, location, quality and credit risk associated with the marketing of LNG and natural gas, we may use futures, swaps and option contracts traded or cleared on NYMEX and over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when:

Our hedging arrangements may also limit the benefit that we would receive from increases in the prices for natural gas. The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

The limited operating history of, and limited capital resources and lack of credit available to, our LNG and natural gas marketing business may limit our ability to develop and grow the business.

We have limited the amount of capital available to our LNG and natural gas marketing business to $40 million, plus overhead expenses and storage charges. The business currently has no access to third-party sources of financing. Other investment-grade marketing companies may have greater financial, technical and marketing resources and access to LNG supply than we do. Our LNG and natural gas marketing business is in its early stages of development and may not generate sufficient revenues and cash flows to cover the significant fixed costs of the business. The lack of capital and credit available to our LNG and natural gas marketing business, along with a lack of cash flows, may inhibit our ability to develop and grow the business.

If we do not attract and retain qualified personnel for our developing LNG and natural gas marketing business, our operations could be adversely affected.

Our success in developing and operating an LNG and natural gas marketing business will be, in part, dependent upon the number and quality of personnel that we can hire and our ability to maintain good relationships with them. We anticipate that we will need to hire additional employees to conduct our natural gas marketing activities. If we are unable to retain qualified employees and then successfully maintain good relationships with them, our results of operations may be adversely affected.

39

Table of Contents

Other risks related to our LNG receiving terminal business could have similar adverse effects on our marketing business.

Some of the risks described above under “—Risks Relating to Our LNG Receiving Terminal Business” could have an adverse impact on our marketing business, including those set forth under the following headings:

Risks Relating to Our Oil and Gas Exploration and Development Business

We may not be successful in our oil and gas exploration and development activities, which may cause this business to become unprofitable.

Our oil and gas exploration and development activities may not be successful if we are not able to find or produce enough oil and gas to generate any profits. Our activities may be curtailed if we are not able to acquire the farm-outs (agreements whereby the owner of lease interests grants to a third party the right to earn an assignment of an interest in the lease, typically by drilling one or more wells), seismic permits, lease options, leases or other rights to explore for or recover oil and gas. Shortages of drilling rigs, equipment or supplies could delay or restrict our exploration and development operations. In addition, because our oil and gas exploration and development business has few employees and limited operating revenues, we are and will continue to be largely dependent on industry partners for the success of our oil and gas exploration projects. Any of these factors could have a material adverse effect on the revenues, results of operations and cash flows of our oil and gas exploration and development business.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future net cash flows.

Numerous uncertainties, including those beyond our control, are inherent in estimating quantities of proved oil and gas reserves. Information included herein for 2006 relating to estimates of our proved reserves is based on reports prepared by Sharp Petroleum Engineering, Inc. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows may vary considerably from the actual results because of a number of variable factors and assumptions involved, including the following:

40

Table of Contents

Therefore, the estimates of the quantities of oil and gas and the expected future net cash flows computed by different engineers or by the same engineers (but at different times) may vary significantly. The actual production, revenues and expenditures related to our reserves may vary materially from the engineers’ estimates. In addition, we may make changes to our estimates of reserves and future net cash flows, which may be based on production history, results of future development, oil and gas prices, performance of counterparties under agreements to which we are a party and operating and development costs.

Do not interpret the PV-10 values included in this Form 10-K as the current market value of our properties’ estimated oil and gas reserves. According to the SEC, the PV-10 is generally based on prices and costs as of the date of the estimate. In contrast, the actual future prices and costs may be materially higher or lower. Actual future net cash flows may also be affected by the following factors:

The timing in producing and the costs incurred in developing and producing oil and gas will affect the timing of actual future net cash flows from proved reserves. Ultimately, the timing will affect the actual present value of oil and gas. In addition, the SEC requires that we apply a 10% discount factor in calculating PV-10 for reporting purposes. This is not necessarily the most appropriate discount factor to apply because it does not take into account the interest rates in effect, the risks associated with us and our properties, or the oil and gas industry in general.

Risks Relating to Our Business in General

We are currently a developing company with limited operating history in the businesses that we are developing. Our business plans are contingent on our ability to manage successfully our anticipated expansion and transition to operating these businesses.

We had net losses of $29.5 and $145.9 million for the years ended December 31, 2005 and 2006, respectively. We expect to continue to incur operating losses and experience negative operating cash flow through 2008 and to incur significant capital expenditures through completion of development of the Sabine Pass LNG receiving terminal. Any delays beyond the expected development periods for the Sabine Pass LNG receiving terminal would prolong, and could increase the level of, our operating losses and negative operating cash flows.

Neither we nor Cheniere has ever managed the construction, operation or maintenance of an LNG facility. We have no experience in the construction or operation of LNG receiving terminals or pipelines or the marketing of LNG or natural gas, and, as a result, we will be forced to rely to a significant extent on the new employees we hire to perform these functions. As our operations expand, we will also have to expand our administrative staff. If we are not able to successfully manage the expansion of our business, our business, results of operation, financial condition and prospects could be materially adversely affected.

41

Table of Contents

Our initiatives to pursue downstream and upstream opportunities as part of our overall energy business strategy may not be successful and, even if successful, could expose us to greater and unanticipated risks.

We have little or no prior experience in some of the downstream opportunities that we are pursuing, such as natural gas pipeline development or natural gas marketing. We also have limited experience in some of the upstream opportunities that we are pursuing, such as investment in LNG shipping businesses and oil and gas exploration, development and transportation. Similarly, we have little or no prior experience in other upstream opportunities that we are pursuing, such as securing foreign LNG supply arrangements and developing foreign natural gas reserves that could be converted into LNG and imported into either domestic or international markets. We may not be successful in our efforts to pursue any or all of these initiatives. If we are successful in pursuing one or more of these downstream or upstream opportunities, we will likely incur greater risks than we expect to incur in our LNG receiving terminal business, and some of those risks we will not be able to anticipate.

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 proposed LNG receiving terminals and pipelines will be subject to the inherent risks often associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in a significant delay in the timing of commencement of operations and/or in damage to or destruction of our facilities 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.

In accordance with customary industry practices, we maintain and intend to maintain insurance against some, but not all, of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, results of operations, financial condition 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, the Clean Air Act, the Oil Pollution Act and the Clean Water Act, 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 terminals and pipelines. 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 frequently proposed legislation implementing a carbon tax on energy sources that emit carbon dioxide into the atmosphere may have a material adverse effect on the ability of our customers: (i) to import LNG, if imposed on them as importers of potential emission sources, or (ii) to sell regasified LNG, if imposed on them or their customers as natural gas suppliers or consumers. In addition, as we consume retainage gas at the LNG receiving terminals, this carbon tax may also be imposed on us directly. Other future legislation and regulations, such as those relating to the transportation and

42

Table of Contents

security of LNG imported to our LNG receiving terminal through navigable waterways, could cause additional expenditures, restrictions and delays in our business and to the planned construction of our LNG receiving terminals, 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.

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

In August and September of 2005, Hurricanes Katrina and Rita and related storm activity, including windstorms, storm surges, floods and tornadoes, caused extensive and catastrophic damage to coastal and inland areas located in the Gulf Coast region of the U.S. (parts of Texas, Louisiana, Mississippi and Alabama) and certain other parts of the southeastern U.S. Construction at the Sabine Pass LNG receiving terminal site was temporarily suspended in connection with Hurricane Katrina, as a precautionary measure. Approximately three weeks after the occurrence of Hurricane Katrina, the terminal site was again secured and evacuated in anticipation of Hurricane Rita, the eye of which made landfall to the east of the site. As a result of these 2005 storms and related matters, the Sabine Pass LNG receiving terminal experienced construction delays and increased costs.

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 terminals, pipelines or related infrastructure.

Terrorist attacks or military campaigns may adversely impact our business.

A terrorist incident involving an LNG facility or LNG carrier may result in delays in, or cancellation of, construction of new LNG facilities, including our proposed LNG receiving terminals and related natural gas pipelines, which would increase our costs and decrease our cash flows and could delay commencement of commercial operations. A terrorist incident may also result in temporary or permanent closure of existing LNG facilities, which, after commencement of commercial operations at our LNG receiving terminals, could increase our costs and decrease our cash flows, depending on the duration of the closure. Operations at our LNG receiving terminals could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect Cheniere Marketing and our customers, including their ability to satisfy their obligations to us under their TUAs.

We depend on key personnel, and we could be seriously harmed if we lost their services.

We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could seriously harm us. In addition, our future success will depend in part on our ability to attract and retain additional qualified personnel.

Some of our economic value is derived from our ownership of minority interests in entities over which we exercise no day-to-day control.

We own a 30% limited partner interest in Freeport LNG and a minority interest in J & S Cheniere. Some of our value is attributable to these investments. In this annual report, we may use the words “our,” “we” or “us” in

43

Table of Contents

describing these investments or their assets and operations; however, we do not exercise control over Freeport LNG or J & S Cheniere. The management team of Freeport LNG or J & S Cheniere could make business decisions without our consent that could impair the economic value of our investments in those entities. Any such diminution in the value of either investment could have an adverse impact on our business, results of operations, financial condition and prospects.

We may have to take actions that are disruptive to our business strategy to avoid registration under the Investment Company Act of 1940.

The Investment Company Act of 1940, or Investment Company Act, requires registration for companies that are engaged primarily in the business of investing, reinvesting, owning, holding or trading in securities. Registration as an investment company would subject us to restrictions that are inconsistent with our fundamental business strategy.

A company may be deemed to be an investment company if it owns investment securities with a value exceeding 40% of the value of its total assets (excluding government securities and cash items) on an unconsolidated basis, unless an exemption or safe harbor applies. Securities issued by companies other than majority-owned subsidiaries are generally counted as investment securities for purposes of the Investment Company Act. We own minority equity interests in certain entities that could be counted as investment securities. We generally plan to invest our liquid assets in commercial paper or other assets that may be considered investment securities in order to achieve higher yields from our available funds than investments in government securities and money market or similar cash investments would provide. Based on our board of directors’ determination of the value of our subsidiaries, we estimate that less than 40% of our assets consist of investment securities. However, in the event we acquire additional investment securities in the future, or if the value of our interests in companies that we do not control were to increase relative to the value of our controlled subsidiaries, we might be required to invest some portion of our liquid assets in government securities or cash items that yield lower returns than our proposed investments, or, in the alternative, we might be required to divest some of our non-controlled business interests, or take other action, in order to avoid being classified as an investment company.

We plan to engage in operations and make investments outside the United States, which would expose us to political, governmental and economic instability and foreign currency exchange rate fluctuations.

Conducting operations or making investments outside of the United States will cause us to be affected by economic, political and governmental conditions in the countries where we engage in business. Any disruption caused by these factors could harm our business. Risks associated with operations and investments outside of the United States include risks of:

Because our reporting currency is the United States dollar, any of our operations outside the United States would face additional risks of fluctuating currency values and exchange rates, hard currency shortages and controls on currency exchange. We would be subject to the impact of foreign currency fluctuations and exchange rate changes on our reporting for results from those operations in our financial statements.

44

Table of Contents

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

We are, and 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, there were no threatened or pending legal matters that would have a material impact on our consolidated results of operations, financial position or cash flows.

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

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5. MARKET PRICE FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock has traded on the American Stock Exchange under the symbol LNG since March 24, 2003. The table below presents the high and low daily closing sales prices of the common stock, as reported by the American Stock Exchange, for each quarter during 2005 and 2006.

The above historical share prices have been adjusted to reflect our two-for-one stock split that occurred on April 22, 2005.

As of February 20, 2007, we had 56.0 million shares of common stock outstanding held by approximately 10,900 beneficial owners.

We have never paid a cash dividend on our common stock. We currently intend to retain earnings to finance the growth and development of our business and do not anticipate paying any cash dividends on the common stock in the foreseeable future. Any future change in our dividend policy will be made at the discretion of our board of directors in light of our financial condition, capital requirements, earnings, prospects and any restrictions under any credit agreements, as well as other factors the board of directors deems relevant.

45

Table of Contents

ITEM 6. SELECTED FINANCIAL DATA

Selected financial data set forth below are derived from our audited Consolidated Financial Statements for the periods indicated. The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and Notes thereto included elsewhere in this report.

46

Table of Contents