Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are engaged primarily in the development of a liquefied natural gas, or LNG, receiving terminal business and related LNG business opportunities centered on the U.S. Gulf Coast.  The LNG receiving terminal business consists of receiving deliveries of LNG from LNG ships, processing such LNG to return it to a gaseous state and delivering it to pipelines for transportation to purchasers.  We are also engaged in oil and gas exploration, development and exploitation activities in the Gulf of Mexico.

Because we are in the preliminary stage of developing LNG receiving terminals, substantially all of the costs related to such activities are expensed as incurred.  Such costs primarily include professional fees associated with front-end engineering and design work and obtaining FERC approval and other required permitting for two LNG receiving terminals located near Sabine Pass, Louisiana and Corpus Christi, Texas and their related natural gas pipelines.  We currently anticipate FERC approval and completion of the permitting process near the end of 2004 with construction of the LNG receiving terminals beginning shortly thereafter.  In addition, we own a 30% limited partnership interest in Freeport LNG, which is developing an LNG receiving terminal site near Freeport, Texas.  This project received FERC approval in June 2004 and construction could begin as early as the end of 2004.

Our unaudited consolidated financial statements and notes thereto relate to the three-month and six-month periods ended June 30, 2004 and 2003.  These statements, the notes thereto and the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2003, as amended, contain detailed information that should be referred to in conjunction with the following discussion.

Results of Operations—Comparison of the Three-Month Periods Ended June 30, 2004 and 2003

Overview —Our financial results for the three months ended June 30, 2004 reflect a loss of $8,052,907, or $0.43 per share (basic and diluted), compared to a loss of $1,624,242, or $0.11 per share (basic and diluted), during the corresponding period in 2003.  The major factors contributing to our loss during the second quarter of 2004 were: (1) LNG receiving terminal development expenses of $5,453,877 (which were offset by a $751,907 minority interest in the operations of Corpus LNG), (2) other general and administrative expenses of $1,605,341 and (3) our equity share of the net loss in Freeport LNG of $1,487,904.

LNG Terminal Development Activities —LNG terminal development expenses were 775% higher in the second quarter of 2004 ($5,453,877) than in the second quarter of 2003 ($623,048).  These expenses were significantly higher in the second quarter of 2004 because we accelerated, beginning in the third and fourth quarters of 2003, the schedule of terminal development at our two sites located near Sabine Pass, Louisiana and Corpus Christi, Texas.  During the first quarter of 2003, we phased out our direct involvement in developing the Freeport LNG terminal site where we now participate through our 30% limited partner interest and record our equity share of partnership net income (loss) under the equity method of accounting.  As a result, second quarter 2003 LNG terminal development expenses did not include any expenses related to the Freeport LNG project and included minimal costs primarily related to the initial start-up of our Corpus LNG project.

During the second quarter of 2004, we recorded $2,402,075 in terminal development expenses related to the Corpus LNG terminal in which we are the general partner and own a 66.7% limited partner

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interest.  This amount was partially offset by $751,907 related to the minority interest of our 33.3% limited partner.  We also incurred $2,292,000 in direct terminal development expenses during the second quarter of 2004 related to the Sabine Pass terminal, where we own 100% of the project.  In addition, in the second quarter of 2004, we incurred $797,400 (before overhead recovery of $225,000 from Corpus LNG) in LNG employee-related costs.  In connection with the expansion of our LNG terminal development business, our employee costs increased as we expanded our LNG staff from an average of 4 to 16 employees from the second quarter of 2003 to the second quarter of 2004.

During the second quarter of 2003, we incurred $623,048 in LNG receiving terminal development expenses.  Of this amount, $420,767 related to initial development costs for the Corpus LNG project.  However, these costs were entirely offset by the minority interest of our 33.3% limited partner who provided 100% of the funding for the first $4,500,000 of partnership expenditures. Because partnership expenditures had reached $4,500,000 as of March 31, 2004, the minority owner began sharing all subsequent expenditures based on its 33.3% limited partner interest.

During the second quarter of 2004, our 30% equity share of the loss from Freeport LNG was $1,487,904 compared to our equity share of the loss of $859,947 for the second quarter of 2003.

Non-Cash Compensation— Non-cash compensation during the second quarter of 2004 is related to restricted stock awards issued in February 2004 to employees and non-employee directors based on Cheniere’s performance in 2003.  The value of these restricted shares was recorded as a reduction to stockholders’ equity as deferred compensation to be amortized over two years as vesting occurs. The $434,999 (net of $43,750 capitalized as oil and gas property costs) recorded in the second quarter of 2004 is entirely related to the amortization of such deferred compensation.

Other General and Administrative Expenses —Other general and administrative (“G&A”) expenses are primarily related to our general corporate and other activities. These expenses increased $1,012,651, or 171%, to $1,605,341 in the second quarter of 2004 compared to $592,690 in the corresponding quarter in 2003.  The primary reasons for the increase in G&A are related to the expansion of our business (including increases in corporate staff from an average of 5 to 15 employees from the second quarter of 2003 to the second quarter of 2004) and increased professional and other fees in connection with securities compliance filings and increased securities registrations.  We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities.  We capitalized $196,300 (in addition to the $43,750 related to non-cash compensation mentioned earlier) in the second quarter of 2004 compared to $248,000 during the comparable period in 2003.

Oil and Gas Activities —Oil and gas revenues increased by $213,346, or 176%, to $334,646 in the second quarter of 2004 from $121,300 in the second quarter of 2003 as a result of a 128% increase in production volumes (56,203 thousand cubic feet of natural gas equivalent (“Mcfe”) in the second quarter of 2004 compared with 24,685 Mcfe in the second quarter of 2003) and a 22% increase in average natural gas prices to $5.99 per thousand cubic feet (“Mcf”) in the second quarter of 2004 from $4.91 per Mcf in the second quarter of 2003.  We had production from an average of 9 wells in the second quarter of 2004 compared to an average of 5 wells in the second quarter of 2003.  We incurred little or no production cost in 2003 and 2004 because all of our revenues were generated from non-cost bearing overriding royalty interests.  The small amount of production cost in 2004 is attributable to our share of production taxes on a producing well located in Texas state waters.

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Results of Operations—Comparison of the Six-Month Periods Ended June 30, 2004 and 2003

Overview —Our financial results for the six months ended June 30, 2004 reflect a loss of $9,127,866, or $0.49 per share (basic and diluted), compared to net income of $1,497,067, or $0.11 per basic share and $0.10 per diluted share, during the corresponding period in 2003.

The major factors contributing to our loss during the first half of 2004 were: (1) LNG receiving terminal development expenses of $9,329,653 (which were offset by a $2,233,379 minority interest in the operations of Corpus LNG), (2) non-cash compensation of $2,260,833 related to 2004 stock awards to employees and non-employee directors based on Cheniere’s performance in 2003 and (3) other general and administrative expenses of $3,240,911.  These factors were partially offset by a $2,500,000 reimbursement from our limited partnership investment in Freeport LNG and our equity share of the net income in Freeport LNG of $667,271.

Net income was recorded in the first half of 2003 as a result of a $4,760,000 gain on the sale of our Freeport LNG assets coupled with a $423,454 gain on the sale of a limited partnership interest in the Freeport LNG terminal.  These gains were partially offset by our equity share of the loss in Freeport LNG of $2,059,947, and LNG receiving terminal development expenses and other general and administrative expenses totaling $2,129,910.

LNG Terminal Development Activities —LNG terminal development expenses were 817% higher in the first half of 2004 ($9,329,653) than in the first half of 2003 ($1,017,109).  These expenses were significantly higher in the second half of 2004 because we accelerated, beginning in the third and fourth quarters of 2003, the schedule of terminal development at our two sites located near Sabine Pass, Louisiana and Corpus Christi, Texas.  During the first quarter of 2003, we phased out our direct involvement in developing the Freeport LNG terminal site where we now participate through our 30% limited partner interest and record our equity share of partnership net income (loss) under the equity method of accounting.  As a result, first half 2003 LNG terminal development expenses only included relatively minor amounts that were directly related to the Freeport LNG project.  Additionally, first half 2003 expenses where significantly less as we had incurred only minimal costs primarily related to the initial start-up of our Corpus LNG project  and, to a lesser extent, our Sabine Pass project.

During the first half of 2004, we recorded $3,883,547 in terminal development expenses related to the Corpus LNG terminal.  This amount was partially offset by $2,233,379 related to the minority interest of our 33.3% limited partner.  Substantially all expenditures incurred through March 31, 2004 were the obligation of the minority owner, as the minority owner was required to fund 100% of the first $4,500,000 of project expenditures.   As project expenditures had reached $4,500,000 by March 31, 2004, the minority owner began sharing all subsequent project expenditures based on its 33.3% limited partner interest.  Also during the first half of 2004, we incurred $4,209,000 in direct terminal development expenses related to our Sabine Pass terminal, in which we own 100% of the project.  In addition, during the first half of 2004, we incurred $1,388,262 (before overhead recovery of $450,000 from Corpus LNG) in LNG employee related costs.  In connection with the expansion of our LNG business, our employee costs increased as we expanded our LNG staff from an average of 3 to 13 employees from the first half of 2003 to the first half of 2004.

During the first half of 2003, we incurred $1,017,109 in LNG receiving terminal development expenses.  Of this amount, $420,767 related to initial development costs for the Corpus LNG project.  However, these costs were entirely offset by the minority interest of our 33.3% limited partner as discussed above.  We also incurred Freeport LNG project costs (incurred prior to the sale), LNG employee costs and initial project costs related to our Sabine Pass LNG receiving terminal.

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In February 2003, our Freeport LNG terminal project was acquired by Freeport LNG in which we received a 40% limited partnership interest and payments to us totaling $5,000,000 over time.  In connection with the sale of LNG assets to Freeport LNG, we reported a gain of $4,760,000.  We also sold a 10% interest in Freeport LNG in March 2003 for $2,333,333, resulting in a gain of $423,454.  During 2003, we received payments totaling $2,500,000 from Freeport LNG, which were recorded as a reduction to our investment in the partnership.  In addition, during 2003 we recorded equity in the 2003 loss incurred by Freeport LNG attributable to our 30% limited partner interest, which reduced our investment to zero as of December 31, 2003.  In January 2004, we received the final $2,500,000 payment from Freeport LNG.  As our investment basis in Freeport LNG had been reduced to zero, the payment was recorded as a reimbursement from limited partnership investment in our consolidated statement of operations for the six months ended June 30, 2004.

During the first half of 2004, our 30% equity share of net income from Freeport LNG was $667,271, after deducting $278,071 of loss that was not recorded as of December 31, 2003.  This compares to our equity share of the loss of $2,059,947 for the first half of 2003.  The significant improvement from a loss to net income between periods for Freeport LNG was a result of Freeport LNG’s receipt of a nonrefundable capacity reservation fee of $10,000,000 from ConocoPhillips in January 2004.

Non-Cash Compensation — N on-cash compensation of $2,260,833 (net of $452,083 capitalized as oil and gas property costs) incurred during the first half of 2004 resulted from bonus and restricted stock awards issued in February 2004 to employees and non-employee directors based on Cheniere’s performance in 2003.  We expensed non-cash compensation in February 2004 related to the issuance of 127,667 shares (bonus stock awards) valued at $15.00 per share, which shares were fully vested on the date of grant.  In addition, we have recorded five months of non-cash compensation related to the amortization of restricted stock awards previously recorded as deferred compensation and amortizable over two years as vesting occurs.

Other General and Administrative Expenses —Other G&A expenses primarily relate to our general corporate and other activities.  These expenses increased $2,128,110, or 191%, to $3,240,911 in the first half of 2004 compared to $1,112,801 in the first half of 2003.  The primary reasons for the increase in G&A are related to the expansion of our business (including increases in corporate staff from an average of 6 to 13 employees from the first half of 2003 to the first half of 2004) and increased professional and other fees in connection with securities compliance filings and increased securities registrations.  We capitalize as oil and gas property costs that portion of G&A expenses directly related to our exploration and development activities.  We capitalized $523,904 (in addition to the $452,083 related to non-cash compensation mentioned earlier) in the first half of 2004 compared to $480,000 during the comparable period in 2003.

Oil and Gas Activities —Oil and gas revenues increased by $435,571, or 188%, to $666,991 in the first half of 2004 from $231,420 in the first half of 2003 as a result of a 191% increase in production volumes (113,840 Mcfe in the first half of 2004 compared with 39,172 Mcfe in the first half of 2003).  Average natural gas prices remained almost level at $5.88 per Mcf in the first half of 2004 compared to $5.91 per Mcf in the first half of 2003.  We had production from an average of 10 wells in the first half of 2004 as compared with an average of 5 wells in the first half of 2003.  We incurred little or no production cost in 2003 and 2004 because all of our revenues were generated from non-cost bearing overriding royalty interests.  The small amount of production cost in 2004 is attributable to our share of production taxes on a producing well located in Texas state waters.

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Liquidity and Capital Resources

We currently anticipate FERC approval and completion of the permitting process for our proposed Sabine Pass and Corpus Christi LNG receiving terminal projects near the end of 2004 with construction of the LNG receiving terminals beginning shortly thereafter.  We intend to finance the construction of the two LNG receiving terminals and our longer-term liquidity needs through issuances of Cheniere debt or equity securities and issuances of project level debt or equity securities or a combination thereof.  We anticipate meeting our more immediate liquidity requirements prior to obtaining FERC approval and completing the permitting processes for the two projects through a combination of cash balances, collection of receivables, issuances of common stock pursuant to exercises by the holders of existing warrants and options, and sales of prospects generated by our exploration group.

  In addition, in January 2004, we initiated the marketing of regas capacity for both of our proposed LNG receiving terminals.  We have actively engaged in the marketing process since that time, seeking long-term contracts for as much as three billion cubic feet per day (“Bcf/d”) of regas capacity.  We are presently in negotiations with potential customers who may become core tenants of our LNG receiving terminals.  We expect that upon execution of each terminal use agreement, we will receive an advance payment for regas capacity sold.  This would provide additional capital to help meet our ongoing liquidity needs.  Furthermore, we intend that such terminal use agreements will serve as collateral to facilitate project level debt financing that we might obtain for the construction of the two LNG receiving terminals.

 There can be no assurance, however, that we will be able to obtain additional capital from one or more of the sources mentioned above.  In the event that we are unable to obtain such additional capital, our operations could be materially and adversely affected.

At June 30, 2004, we had working capital of $8,446,404 compared to $155,526 at December 31, 2003.  The increase is primarily attributable to the sale of our common stock through a private placement offering in January 2004 and exercises of warrants and stock options that resulted in aggregate net proceeds of $16,398,335.  We also received a $2,500,000 payment from Freeport LNG, which was payable pursuant to the sale of a 60% interest in the Freeport LNG project, and $2,186,000 in partnership contributions from our Corpus LNG minority owner.  Major uses of working capital included $12,570,564 related to LNG terminal development and other general and administrative expenses during the six months ended June 30, 2004.

Cash Flow Used in Operating Activities

Net cash used in operations for the six months ended June 30, 2004 totaled $10,584,285, compared to net cash used in operations of $2,446,692 for the same period in 2003.  The increase in cash used in operations is a direct result of the expansion of our LNG receiving terminal business.  In the first quarter of 2003, we phased out our direct involvement in developing the Freeport LNG terminal site, but in subsequent periods, we accelerated the development schedule of our Sabine Pass LNG and Corpus LNG terminals.

Issuances of Common Stock

In January 2004, we issued 1,100,000 shares of Cheniere common stock in a private placement under Regulation D to twelve accredited investors for total consideration of $14,850,000, or $13.50 per share.  The Company paid a 6.5% sales commission totaling $965,250, resulting in $13,884,750 of net proceeds received from the offering.  The proceeds of the private placement will be used primarily for the development of LNG receiving terminals and for general corporate purposes.

On February 2, 2004, under the 2003 Stock Incentive Plan, 383,000 shares were issued to employees and outside directors in the form of bonus and restricted stock awards related to our overall

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2003 performance.  We recorded $1,915,000 of non-cash compensation in February 2004 related to the issuance of 127,667 shares (bonus stock awards) valued at $15.00 per share that were fully vested on the date of grant.  In addition, we recorded $3,830,000 of deferred compensation as a reduction to stockholders’ equity related to the issuance of 255,333 shares (restricted stock awards) valued at $15.00 per share on the grant date that vests on each of the first and second anniversaries of the grant date.  As of June 30, 2004, $797,917 of deferred compensation had been amortized.

In the first half of 2004, a total of 582,057 shares of Cheniere common stock were issued pursuant to the exercise of stock options, resulting in net cash proceeds of $1,102,961.  An additional 159,715 shares of Cheniere common stock were issued in satisfaction of cashless exercises of options to purchase 189,612 shares of common stock.  A total of 357,500 shares of Cheniere common stock were also issued pursuant to the exercise of warrants, resulting in net proceeds of $1,410,625.

Bank Line of Credit

On June 23, 2004, we terminated our $5,000,000 line of credit with a commercial bank.  This facility was originally established on July 25, 2003 with a borrowing base of $2,000,000.  The facility was secured by our assets, and its term, as amended, ran through December 31, 2004.  Borrowings bore interest at the bank’s prime rate plus 2.5% per annum. In addition, a commitment fee of 0.5% per annum was assessed on the unused borrowing base capacity.  A loan origination fee of 1% of the initial borrowing base was paid at closing.  During 2003, we borrowed $1,000,000 under the facility to acquire oil and gas leases.  The balance was repaid in January 2004. We also used the facility to establish a standby letter of credit in the amount of $865,142 in connection with our office lease.  In April 2004, the letter of credit amount was increased to $1,123,094 related to the planned expansion of our office space.

Restricted Certificate of Deposit

In conjunction with the termination of our line of credit,  we purchased a certificate of deposit in the amount of $1,123,094.  We also entered into a pledge agreement in favor of the commercial bank that had previously issued a letter of credit for $1,123,094 related to our office lease.  Under the terms of the pledge agreement, the commercial bank was assigned a security interest in the certificate of deposit as collateral for the letter of credit.  As a result, the certificate of deposit is classified as restricted on our balance sheet at June 30, 2004.  The certificate of deposit matures on November 15, 2004 and bears a fixed interest rate of 1.7% per annum.

Off-Balance Sheet Arrangements

As of June 30, 2004, we had no “off-balance sheet arrangements” that may have a current or future material affect on our consolidated financial condition or results of operations.

Freeport LNG Receiving Terminal

In August 2002, we entered into an agreement to sell a 60% interest in our planned LNG receiving facility near Freeport, Texas.  In February 2003, our Freeport LNG project was acquired by Freeport LNG, in which we held a 40% interest.  Effective March 1, 2003, we sold a 10% interest in Freeport LNG to Contango for $2,333,333 payable over time.  We now retain a 30% interest in Freeport LNG.  Freeport LNG paid us cash and assumed liabilities related to the Freeport LNG project for costs, which represented an aggregate amount of $1,740,426, in addition to paying us a $1,000,000 initial installment at closing.  We received additional payments of $1,500,000 in 2003 and $2,500,000 in January 2004 from Freeport LNG.

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In June 2003, Dow Chemical Company (“Dow”) signed an agreement with Freeport LNG for the potential long-term use of the receiving terminal.  Under the agreement, Dow will have regas rights to as much as 500 Mmcf/d beginning with commercial start-up of the facility in 2007.  On March 1, 2004, Freeport LNG and Dow entered into a 20-year Terminal Use Agreement providing for a firm commitment by Dow for the use of 250 Mmcf/d of regas capacity and an option by Dow until August 31, 2004 to acquire an additional 250 Mmcf/d of regas capacity.

On December 21, 2003, ConocoPhillips and Freeport LNG signed an agreement under which ConocoPhillips would reserve one Bcf/d of regas capacity in the terminal at the Freeport facility.  ConocoPhillips would also obtain a 50% interest in the general partner of Freeport LNG and provide a substantial majority of the financing to construct the facility, which is currently estimated to cost in excess of $500,000,000.  Freeport LNG received a nonrefundable capacity reservation fee of $10,000,000 from ConocoPhillips in January 2004.  The ConocoPhillips transaction closed in July 2004.

Under the Freeport LNG partnership agreement, development expenses of the Freeport LNG project are to be funded out of the partnership’s cash flows and by its 60% limited partner.  Accordingly, we have not been called upon to contribute any cash to Freeport for development activities, nor do we anticipate being called upon to make capital contributions in order for Freeport LNG to complete construction of the facility to be financed pursuant to the agreements with ConocoPhillips.  If, in the future, we were to be called upon to contribute additional capital to Freeport LNG, for expansion of the project or any other purpose, we would have the option either to contribute the requested capital or else to decline to contribute, in which case the other partners could elect to make our contribution and receive back, without interest, twice the contributed amount out of future Freeport LNG cash flows otherwise distributable to us.

Corpus Christi LNG Receiving Terminal

Under the terms of the limited partnership agreement of Corpus LNG, which was formed in May 2003 for our Corpus LNG receiving terminal project, we contributed our technical expertise and know-how and all of the work in progress related to the Corpus Christi project, in exchange for a 66.7% limited partner interest in Corpus LNG.  We also manage the project through the general partner interest held by our wholly-owned subsidiary.  BPU LNG committed to contribute its approximately 210-acre tract of land plus related easements along with rights to an additional 400 acres, and cash to fund 100% of the first $4,500,000 of Corpus LNG project expenditures in exchange for a 33.3% limited partner interest.  Because partnership expenditures had reached $4,500,000 as of March 31, 2004, BPU LNG began sharing all subsequent expenditures with us based on the percentages of our respective limited partner interests.

Contractual Obligations

On May 11, 2004, we amended our office lease in order to expand our existing office space (the “Expansion Space”).  The term for the Expansion Space is for five years with an option, subject and subordinate to another tenant’s renewal option, to renew for a term that would coincide with the term of our existing space that terminates January 2014.   No rent is payable for the first nine months of the five-year term.  Total payments for the remainder of the five-year lease term are $200,292 per year.

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Other Matters

New Accounting Pronouncements

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities , and subsequently revised the Interpretation in December 2003 (FIN 46R).  This Interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements , addresses consolidation by business enterprises of variable interest entities, which have certain characteristics.  As revised, FIN 46R is now generally effective for financial statements for interim or annual periods ending on or after March 15, 2004.  We adopted FIN 46R effective January 1, 2004, with no material effect on our consolidated financial statements.

Other Recent Developments

In July 2003, an issue was brought before the FASB regarding whether or not contract-based oil and gas mineral rights held by lease or contract (“mineral rights”) should be recorded or disclosed as intangible assets.  The issue presents a view that these mineral rights are intangible assets as defined in Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations,” and, therefore, should be classified separately on the balance sheet as intangible assets.  SFAS No. 141 and SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective for transactions subsequent to June 30, 2001, with the disclosure requirements of SFAS No. 142 required as of January 1, 2002. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that intangible assets be disaggregated and reported separately from goodwill.  SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets.  Under the statement, intangible assets should be separately reported on the face of the balance sheet and accompanied by disclosure in the notes to financial statements.  SFAS No. 142 does not apply to accounting utilized by the oil and gas industry as prescribed by SFAS No. 19, and is silent about whether or not its disclosure provisions apply to oil and gas companies.

In July 2004, the FASB proposed FSP FAS 142-b, “Application of FAS 142 to Oil and Gas Producing Entities.” The proposed FSP clarifies that the exception in paragraph 8(b) of SFAS No. 142 includes the balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing entities. Accordingly, the FASB staff believes that the  exception extends to the disclosure provisions of SFAS No. 142 for drilling and mineral rights of oil and gas producing entities. The consensus will be effective when the FSP is finalized.