UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended June 30, 20042005

Commission file number 000-24971

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

3700 Buffalo Speedway, Suite 960

Houston, Texas 77098

(Address of principal executive offices)

(713) 960-1901

(Issuer’s telephone number)

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

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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.x¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).    Yes  x    No  ¨

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 voting common equity held by non-affiliates computed by reference to the average bid and asked price of such common equity at the close of business on September 15, 2004,7, 2005, was $48,054,646.$137,420,706. As of September 15, 2004,7, 2005, there were 12,977,36614,714,471 shares of the issuer’s common stock outstanding.

Documents Incorporated by Reference

Items 10, 11, 12, 13 and 14 of Part III have been omitted from this report since registrant will file with the Securities and Exchange Commission, not later than 120 days after the close of its fiscal year, a definitive proxy statement, pursuant to Regulation 14A. The information required by Items 10, 11, 12, 13 and 14 of this report, which will appear in the definitive proxy statement, is incorporated by reference into this Form 10-K.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K FOR THE FISCAL ENDED JUNE 30, 20042005

TABLE OF CONTENTS

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Cautionary Statement About Forward-Looking StatementsCAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Some of the statements made in this Form 10-Kreport may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. These include such matters as:

Although we believe the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will occur. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These factors include among others:

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You should not unduly rely on these forward-looking statements in this Form 10-K,report, as they speak only as of the date of this Form 10-K.report. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this Form 10-Kreport or to reflect the occurrence of unanticipated events. See the information under the heading “Risk Factors” in“Risk Factors�� referred to on page 19 of this Form 10-Kreport for some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in forward-looking statements.

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All references in this Form 10-K to the “company”“Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and wholly-owned Subsidiaries. Unless otherwise noted, all information in this Form 10-K relating to natural gas and oil reserves and the estimated future net cash flows attributable to those reserves are based on estimates prepared by independent engineers and are net to our interest.

General information about us can be found on our Website atwww.contango.com. Our Annual Reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our Website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission.

PART I

Item 1.Business

Overview

We are anContango is a Houston-based, independent natural gas and oil company engaged in the exploration, productioncompany. The Company’s core business is to explore, develop, produce and acquisition ofacquire natural gas and oil in the United States, both onshore Gulf Coast andproperties primarily offshore in the Gulf of Mexico. Our primary source of natural gasMexico and oil production currently is in south Texas. Weonshore along the Gulf Coast. As a recent addition to our business, we will begin acting as an operator on certain offshore prospects through our wholly-owned subsidiary, Contango Operators, Inc. (“COI”). The Company also ownowns a 10% partnership interest in Freeport LNG Development, L.P., which is developing a 1.5 Bcf per daylimited partnership formed to develop an LNG receiving terminal in Freeport, Texas, and have a 32% interest in Contango Capital Partnership Management, LLC, which was formed to investholds investments in the alternative energy venture capital market.

As of June 30, 2004, we owned approximately 17.4 Bcfe of total proved reserves, compared to 23.6 Bcfe as of June 30, 2003. As of June 30, 2004 and 2003, approximately 99% and 97% of total proved reserves, respectively, were classified as proved developed producing. The pre-tax net present value of our total proved reserves prepared in accordancemarket with the Securities and Exchange Commission (the “SEC”) guidelines as of June 30, 2004 was approximately $59.8 million, compared to $69.6 million as of June 30, 2003.

Total revenues and EBITDAX for the year ended June 30, 2004 were $27.7 million and $29.0 million, respectively. For the year ended June 30, 2003, total revenues and EBITDAX were $28.2 million and $20.9 million, respectively. We define EBITDAX as earnings before interest, income taxes, depreciation, depletion and amortization, impairment expense and expensed exploration expenditures, including gains (losses) from hedging activities, and sale of assets and other. See Item 6. “Selected Financial Data” for more information about the calculation of EBITDAX and its uses. Average net daily production for the year ended June 30, 2004 was 11.8 MMcf of natural gas and 272 barrels of oil per day, compared to 16.5 MMcf of natural gas and 380 barrels of oil per day for the year ended June 30, 2003.a focus on environmentally preferred energy technologies.

Our Strategy

Our exploration strategy is predicated upon two core beliefs: (1) that the only competitive advantage in the commodity-based natural gas and oil business is to be among the lowest cost producers and (2) that virtually all the exploration and production industry’s value creation occurs through the drilling of successful exploratory wells. As a result, our business strategy includes the following elements:

Funding exploration prospects developedgenerated by our alliance partners. Because we only have four employees, weWe depend on alliance partners for exploration, development and productionprospect generation expertise. Our four alliance partners, Juneau Exploration, L.P. (“JEX”), Alta Resources, LLC (“Alta”), Ameritex Minerals and Exploration, Ltd. (“Ameritex”) and Coastline Exploration, Inc. (“Coastline”) perform all of our prospect generation and evaluation functions.

Using our capital availability to increase our reward/risk potential on selective prospects. Beginning in the spring of 2005, we decided to increase our capital investment in our onshore Fayetteville Shale prospect area as well as two of our offshore prospects: Eugene Island 10 and Grand Isle 72. Our initial capital investment in each of these three prospects is estimated to require $5 million. This represents a major increase in the risk profile of the Company which in the past has limited its dry hole risk exposure on any one well to approximately $1 million. Our estimated cost commitment could be significantly larger if we encounter difficultly in drilling these wells.

Operating in the Gulf of Mexico.Contango Operators, Inc. (“COI”) is a wholly-owned subsidiary of the Company, formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico and is a new element of our business strategy. COI will operate for the first time and will drill two exploration wells in the Gulf of Mexico. This represents an increase in the risk profile of the Company since the Company has never before operated. COI will be the entity under which Contango will operate selective offshore prospects.

Negotiated acquisitions of proved properties. We continue to seek negotiated acquisitions of producing property acquisitionsproperties based on our view of the pricing cycles of natural gas and oil and available reserve exploitation opportunities of probable and possible reserves.opportunities. Since January 1, 2002, we have acquired approximately 14.0 Bcfe14 billion cubic feet equivalent (“Bcfe”) of proved developed producing reserves of natural gas and oil for approximately $26.0$26 million.

Sale of proved properties. From time-to-time as part of our business strategy, we have sold and in the future may sell some or a substantial portion of our proved reserves to capture current value, using the sales proceeds to further our exploration, LNG and alternative energy investment activities.

In JulySeptember 2003, we sold producing properties consistingthe Company completed the sale of 10 wellscertain reserves in southBrooks County, Texas for $5.0 million. million and recorded a gain of approximately $0.9 million for the year ended June 30, 2004. Proved reserves were 1.5 Bcfe and accounted for approximately $5.0 million of the Company’s discounted present value at 10% per annum as of June 30, 2003.

In December 2003, Contango and its 33%-owned subsidiary, Republic Exploration, LLC (“REX”), our partially owned subsidiary, sold all of their then producing Gulf of Mexico leases for approximately $12.0 million. As a result of this sale, Contango recorded a gain of approximately $6.2 million for the year ended June 30, 2004. Properties included in the sale were Eugene Island 110, Grand Isle 28 and High Island 25-L.

In December 2004, we sold producing properties consisting of 39 wells in south Texas, a majority of our natural gas and oil interests, for $50 million to Edge Petroleum Corporation. The sale was approved by a majority of the Company’s stockholders at a Special Meeting of Stockholders on December 29, 2004. Approximately 16 Bcfe of proven reserves were sold having a pre-tax net present value when using a 10% discount rate as of June 30, 2004 of $54.3 million. Pre-tax proceeds after netting adjustments were $40.1 million.

In accordance with Statement of Financial Accounting Standards No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” we classified our December 2004 property sale to Edge Petroleum and our September 2003 Brooks County sale as discontinued operations.

Since its inception, the Company has sold over $67 million worth of oil and natural gas properties, and views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, and as a source of funds for potentially higher rate of return natural gas and oil exploration opportunities.

Controlling general and administrative and geological and geophysical costs. Our goal is to be among the highestmost efficient in the industry in revenue and profit per employee and among the lowest in general and administrative costs. WeWith respect to our onshore prospects, we plan to continue outsourcing our geological, geophysical, reservoir engineering and land functions, and partnering with cost efficient operators whenever possible.operators. We currently have foursix employees.

Structuring transactions to minimize front-end investments. We seek to maximize returns on capital by minimizing our up-front investments in acreage, seismic data and prospect generation whenever possible. We want our partners to share in both the risk and the reward of our success.

Diversified energy investments. While our core focus is the domestic exploration and production business, we will continue to seek opportunities that may include foreign exploration prospects or investments related to new and developing energy sources such as LNG and alternative energy (see below).energy.

Structuring incentives to drive behavior. We believe that equity ownership aligns the interests of our partners, employees, and stockholders. Our directors and executive officers beneficially own approximately 22% of our common stock. In addition, our alliance partners co-invest in prospects that they recommend to us.

Exploration Alliances with JEX, Alta, Resources, Ameritex and Coastline

Alliance with JEX.JEX was our first alliance partner.Underis a private company formed for the purpose of assembling domestic natural gas and oil prospects. Under our agreement with JEX, JEX generates natural gas and oil prospects and evaluates exploration prospects generated by others. In exchange, we have committed, within various parameters, to invest along with JEX up to 95% of the available working interest in the recommended prospects. Infocuses exclusively on the Gulf of Mexico, JEX bringsand generates offshore exploration prospects directly tovia our affiliated companies, Republic Exploration, LLCREX and Contango Offshore Exploration, LLC (“COE”) (see “Offshore Gulf of Mexico Exploration Joint Ventures” below).

If JEX recommends an onshore prospect to Contango, we pay the lease and seismic costs, and JEX generally pays the remaining costs of generating and preparing a prospect to drill ready status. When drilling begins on a prospect, we are obligated to assign to the JEX geoscientists an overriding royalty interest equal to 3 ¹/3% of our working interest in the prospect. In addition, when our revenues from prospects we invest in under the agreement, net of taxes, royalties and other expenses equals our capital expenditure related to the exploration and development of the prospects on a well-by-well basis, JEX is entitled to an assignment of 25% of our working interest in the well.

We may terminate the agreement upon 30 days written notice, and JEX may terminate the agreement upon 180 days notice. If we are in default under the agreement, however, JEX may terminate the agreement upon 30 days written notice.

Offshore prospects are typically generated by our partially owned subsidiaries, Republic Exploration LLC and Contango Offshore Exploration LLC. JEX is the managing partner of both entities. See “Offshore Gulf of Mexico Exploration Joint Ventures” below.

Alliance with Alta Resources.Alta. Alta Resources is a private company formed for the purpose of assembling domestic, onshore natural gas and oil prospects. Our arrangement with Alta Resources generally provides for us to pay our share of seismic and lease costs, with Alta Resources generally receiving a negotiated overriding royalty interest and a carried or back-in working interest.

Alliance with Ameritex.In February 2004, we entered into an exploration agreement with Ameritex, a privately held San Antonio based prospect generation and exploration company. Our participation percentage, which is exercisable at our option, is typically a 33.3% working interest, with Ameritex beingreceiving a carried working interest to casing point. Ameritex’s activities are concentrated on the generation of exploration opportunities utilizing 3-D seismic technology. TheOur annual G&Ggeological and geophysical cost to Contango for this prospect generation effort is approximately $80,000 per year.$80,000.

Alliance with Coastline.Coastline is a private company engaged in domestic, onshore natural gas and oil exploration and production. In late 2003, we entered into our original agreement with Coastline to explore for and develop natural gas and oil prospects in Kenedy County, Texas. Our arrangement with Coastline generally provides for us to pay all leasehold costs, with Coastline generally receiving a negotiated overriding royalty interest and a carried working interest to casing point.

Domestic Onshore Exploration and Properties

JEX Activities

JEX was our first alliance partner. Between May 2000 and March 2004, we drilled 49 wells with JEXis focused on our south Texas properties in Jim Hogg and Brooks Cos., Texas, resulting in 34 successes. We have no further drilling plans on this acreage.

While JEX continues a limited onshore exploration effort for us, JEX’s principle activity is the exploration management ofprospect generation via our affiliated offshore Gulf of Mexico exploration companies. See “Offshore Gulf of Mexico Exploration and Joint Ventures”.

Alta Resources Activities

In October 2003, Contango and Alta Resources completed a 3-D seismic shoot covering approximately 40 square miles in southern Duval County, Texas. The net cost to us was approximately $1.7 million. TwoUsing this data, Contango and Alta successfully drilled two Queen City prospects have been successfully drilled andthat commenced production in September 2004. Two additional shallow prospects have been identified and are expected to be drilled prior to calendar year end 2004.

We recentlyIn October 2004, we participated with Alta Resources in drilling a third exploratory Queen City well in Jim Hogg County, Texas. The well was determined to be a dry hole and has since been plugged and abandoned. Our 45% share of the dry hole cost was approximately $0.4 million.

In August 2004, we participated with Alta in drilling an unsuccessful exploratory Frio well located in Matagorda County, Texas. The dry hole cost was approximately $1.4 million, of which our share was $0.7approximately $0.6 million.

WeIn January 2005, Contango and Alta successfully drilled two shallow wells in Duval County. The Fitzsimmons #1, in which we have a 33% net revenue interest, is a natural gas well. The Marshbanks #1, in which we have a 32% net revenue interest, is an oil well. Both wells have been completed and are currently participating withproducing commercial quantities of natural gas and oil.

In January 2005, Contango and Alta elected to participate in anthree exploratory Queen Citywells in Escambia County, Alabama. Our share of geological and geophysical costs on the three prospects was approximately $0.3 million. We expect to drill the first well in Jim Hogg County, Texas.by fall 2005, for which our 75% share of dry hole costs is estimated at $1.1 million. We expect to drill the last two remaining exploratory wells by the first quarter of 2006. Our 45%75% share of the dry hole costcosts for these two remaining wells is estimated at $0.4to be $1.8 million.

In addition,March 2005, Contango and Alta entered into a Participation Agreement to acquire natural gas, oil, and mineral leases in the Fayetteville Shale play area located in Pope, Van Buren, Conway, Faulkner, Cleburne, and White Counties, Arkansas. Under the Participation Agreement, we have agreed to participateincur lease acquisition costs for our 70% share, up to $4.2 million. We have since increased our commitment to a total of approximately $5.6 million. As of September 7, 2005 Alta had acquired or received commitments on approximately 32,000 acres at a cost of approximately $6.9 million. Our 70% share of the acquisition costs is about $4.8 million. Alta expects to acquire an additional 3,000 acres by the end of calendar year 2005 to bring the total to approximately 35,000 acres.

A number of drillable prospects have been identified and Alta expects to begin drilling horizontal wells in the first calendar quarter of 2006. These wells are estimated to cost approximately $1.7 million each with our 70% share of drilling costs estimated at $1.2 million. At project payout, Alta will be assigned a 20% reversionary working interest, proportionately reduced to Contango, Alta and the other participants. Alta will receive an overriding royalty interest in each lease assignment contingent on the amount of lease burden assigned to the third party royalty owners. We estimate our net revenue interest in this play, after Alta’s 20% reversionary working interest, will be 45%.

In June 2005, we participated with Alta in drilling an unsuccessful exploratory well in Bandera County, Texas. We expect to drill this prospect by mid-year 2005. Our 50% share of the dry hole cost was approximately $0.6 million.

In June 2005, we successfully drilled two shallow exploratory wells, the Vanco #1 and the Vanco #2. Drilling and completion costs for each well were approximately $0.1 million. Our net revenue interest in each well is approximately 16%. Both wells have been completed and are currently producing commercial quantities of natural gas and oil.

In June 2005, Alta elected to participate in two exploratory wells in the Fayetteville Shale being drilled by another independent oil and gas company. The first exploratory well, the Sneed #1-31, was a vertical well that was successfully drilled and initially tested at a rate of 932 thousand cubic feet per day (“Mcf/d”). Our net revenue interest in the Sneed #1-31 well is approximately 2.4%. The second exploratory well, the Sneed #1-6 was drilled in June 2005. Our net revenue interest in the Sneed #1-6 is estimated at $0.6 million.4.7%. Alta has been notified by this same independent oil and gas company that we will have the opportunity to invest as working interest owners in another four wells scheduled to be drilled before calendar year-end 2005.

Ameritex Activities

In February 2004, we entered into an exploration agreement with Ameritex. Ameritex has currently identified eightfour prospect areas. Amertiex has successfully drilledareas in which we will participate, all of which are located in south Texas.

In March 2005, we participated with Ameritex in drilling an 11,400-foot Wilcox test in one prospect areaexploratory well, the Garza #1, located in Zapata County, Texas. The well was determined to be a dry hole and has been plugged and abandoned. Our 19% share of dry hole and leasehold costs was approximately $1.2 million. We have a 14% net revenue interestalso drilled two exploratory wells, the Hargis #1 located in this well. Another Wilcox test is planned for a second prospect area in ZapataLive Oak County, Texas next year.and the Thompson #1 located in Zavala County, Texas. Both wells were determined to be dry holes and have since been plugged and abandoned. Our 18.8%29.5% share of the dry hole costand leasehold costs for both wells was approximately $0.8 million.

In May 2005, Contango sold its 29.5% interest in seismic and leasehold property in the Glen Rose, San Miguel and Austin Chalk prospect areas of Dimmit and Zavala Counties, Texas, for $23,750 but retained a 7.4% back-in working interest after payout.

In June 2005, we successfully drilled the Gonzalez Benavides Trust #1, an exploratory well located in Zapata County, Texas. Our 33% share of the drilling costs is estimated at $0.7 million and our net revenue interest is approximately $0.8 million. Prospect generation18.8%. The well has been completed and is continuing on identified prospect areas.currently awaiting a pipeline connection. Production is expected to begin in October 2005.

In addition, we expect to drill three exploratory wells by the end of the calendar year 2005 in the Normanna, Caney Creek and Payday prospect areas located in Bee, Matagorda and Duval Counties, Texas, respectively. Our working interest share of the dry hole costs for these three wells is estimated at $2.2 million.

Coastline Activities

In SeptemberOctober 2004, we entered intoCoastline purchased 3-D seismic data on an agreementapproximate 22 square mile area along with a lease option for an initial 180 day period, providing Coastline the right to generate prospectspurchase leases on 15,060 acres in Jim Hogg County, Texas using available 3-D seismic data. Contango hasTexas. The lease option was renewed for an additional 90 days and expired. We agreed to reimburse Coastline $100,000 for geological and geophysical costs. If drillable prospects are identified, we will pay all100% of the prospect leasehold costs and carry Coastline on a portion of the drilling costs on a specified number of wells.the first three wells located within the designated prospect area. In addition, Coastline willwould receive ana 3% overriding royalty interest.

International Onshore ExplorationIn December 2004, Coastline purchased 3-D seismic data on an approximate 41 square mile area along with a 180-day lease option, providing Coastline the right to purchase leases on 29,694 acres in Jim Hogg County, Texas. Coastline has since exercised part of its option and has purchased a lease on 1,920 acres. Our share of the lease acquisition costs was approximately $0.4 million. No drillable prospects were identified and in July 2005, we elected to allow both of our lease options to expire. We have since declined to invest in any further prospects related to the above acreage and have expensed the remaining capital investment of approximately $1.2 million as of June 30, 2005.

In May 2005, we drilled a shallow exploratory well located in Jim Hogg County which proved to be unsuccessful. Our 100% share of dry hole costs for this shallow well was approximately $0.2 million.

Sale of South Texas Properties

In December 2004, the Company completed the sale of the majority of its south Texas natural gas and oil interests to Edge Petroleum Corporation for $50 million. The sale was approved by a majority of the Company’s stockholders at a Special Meeting of Stockholders on December 29, 2004. Approximately 16 Bcfe of proven reserves were sold having a pre-tax net present value using a 10% discount rate as of June 30, 2004 of $54.3 million. Pre-tax proceeds after netting adjustments were $40.1 million. Adjustments were made for net revenues that Contango received for production occurring after July 1, 2004, the effective date of sale, up to the post-closing date of March 2004, Contango and Texas Petroleum Investment29, 2005. The Company agreed to pursue an oil exploration prospect inrecognized a gain on sale of approximately $16.3 million for the Aquitaine Basin in southwestern France. The initial well was drilled to approximately 10,500 feet and was a dry hole. The cost of this well was approximately $4.0 million, with Contango’s 20% dry hole cost of $0.8 million. We have no future plans in France.year ended June 30, 2005.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. Currently,As of June 30, 2005, Contango and its affiliates had interests in 50 offshore leases. As of September 7, 2005, Contango and its affiliates have interests in 4252 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.

As of June 30, 2005 Contango owns anowned a 33.3% equity interest in RepublicREX, a 66.7% equity interest in COE, and a 50.0% equity interest in Magnolia Offshore Exploration and Contango Offshore Exploration,LLC (“MOE”), all of which were formed for the purpose of generating exploration opportunities in the Gulf of Mexico. These companies have collectively licensed approximately 4,0003,800 blocks of 3-D seismic data and have focused on identifying prospects, acquiring leases at federal and state lease sales and then selling the prospects to third parties, including Contango, subject to timed drilling obligations plus retained reversionary interests in favor of Republic ExplorationREX and Contango Offshore Exploration. In the future, Contango may choose to take a direct working interest in some of these prospects under the same arms-length terms available to industry partners. JEX is the managing member of Republic Exploration and Contango Offshore Exploration.COE.

Republic Exploration LLC.As of June 30, 2005, Contango had approximately $5.7 million invested approximately $6.7 million in Republic Exploration in August 2000REX for a 33.3% ownership interest. The other members of Republic ExplorationREX are JEX, its managing member, and a privately held seismic company. Both have comprehensive offshore experience. Republic ExplorationREX holds a non-exclusive license to approximately 1,7002,030 blocks of 3-D seismic data in the shallow waters of the Gulf of Mexico. This data is used to identify, acquire and exploit natural gas and oil prospects. All leases owned by Republic ExplorationREX are subject to a 3.3% overriding royalty interest in favor of the JEX explorationprospect generation team. See “Offshore Properties” below for more information on Republic Exploration’sREX’s offshore properties. In addition, please see “Subsequent Events” on page F-25 for a discussion of our recent purchase of additional interests in REX.

Contango Offshore Exploration LLC.As of June 30, 2005, Contango purchasedhad approximately $13.7 million invested in COE for a 66.7% interest in Contango Offshore Exploration in September 2002.ownership interest. JEX is the only other member and acts as the managing member. Contango Offshore Exploration’s activities will be focused on identifying and purchasing prospects in the Gulf of Mexico and selling them to third parties, retaining a reversionary interest. Contango Offshore Exploration hasCOE had invested approximately $13.6$13.7 million to acquire and reprocess 2,2941,775 blocks of 3-D seismic data and to acquire leases in the Gulf of Mexico. All leases will beare subject to a 3.3% overriding royalty interest in favor of the JEX explorationprospect generation team. See “Offshore Properties” below for additional information on COE’s offshore properties. In addition, please see “Subsequent Events” on page F-25 for a discussion of our recent purchase of additional interests in COE.

Magnolia Offshore Exploration LLC. As of June 30, 2005, Contango had approximately $0.9 million invested in MOE. Contango purchased a 50% working interest in MOE in October 2001. JEX is the only other member of Magnolia Offshore Exploration’s properties.Exploration and acts as the managing member, deciding which prospects Magnolia Offshore Exploration may acquire, develop, and exploit. MOE owns license rights to 3-D seismic data covering 600 blocks of the Gulf of Mexico continental shelf.

Current Activities.OnAs of June 30, 2005, our Eugene Island 76 prospect was successfully tested and production is expected to begin by the end of fall 2005. REX was carried in the well and owns an overriding royalty interest of 5% until payout, after which REX will receive an 8.33% overriding royalty interest with an option to elect a 25% working interest upon payout.

In March 17, 2004, Republic Exploration2005, REX and Contango Offshore Exploration bidCOE were high bidders on 37three lease blocks that were offered at the Central Gulf of Mexico Lease Sale #190 held in New Orleans and were awarded 24 blocks. Each of these blocks is located on#194. REX acquired the shelf of theWest Cameron 107 offshore Gulf of Mexico in water depthslease block for approximately $0.3 million and COE acquired the Viosca Knoll 475 offshore Gulf of less than 200 meters. Contango currently own interests, both directlyMexico lease block for approximately $0.3 million and indirectly through its affiliates, in 42 federal lease blocksREX and COE each acquired a 50% working interest in the Eugene Island 168 lease block.

In July 2005, REX acquired State Lease No. 18640, a 474.5 acre tract located off the coast of Louisiana covering a portion of offshore blocks Eugene Island 10 and 11 and is located approximately three miles offshore in 11 feet of water. The purchase price for the acreage was approximately $0.7 million. This lease block is contiguous to our farm-in block, Eugene Island 10.

In August 2005, COE was the apparent high bidder on two blocks offered at the Western Gulf of Mexico.Mexico Lease Sale #196, the East Breaks 366 and the East Breaks 410 blocks. The bid price for the two blocks was approximately $0.6 million. The blocks are complementary to our East Breaks 369 and 370 prospects and are located in approximately 2,000 feet of water.

In May 2003, ContangoREX and Republic ExplorationCOE have farmed out Eugene Island 113B. This well is currently drilling. Republic Exploration and Contango Offshore Exploration recently farmed outthe following five lease blocks, Vermilion 73,blocks: Main Pass 221, East Breaks 369/370, Vermillion 154, and the West Cameron 174, Eugene Island 76, Vermilion 154 and133. Main Pass 221. An exploratory well to test a deep sand on Vermilion 73 was unsuccessfully drilled earlier this year. A shallower formation221 is expected to be drilled later this year.by the end of calendar year 2005, in which COE will receive a 5% overriding royalty interest before payout and a 7.2% overriding royalty interest after payout.

East Breaks 369 is expected to spud prior to the end of the first calendar quarter 2006 and East Breaks 370 is expected to spud prior to September 2007. COE will receive a 4.27% overriding royalty interest before payout and a 7.2% overriding royalty interest after payout on the East Breaks 369/370 prospects.

REX has recently entered into a letter of intent to farm out and drill an exploratory well on West Cameron 174, Eugene Island 76133, whereby REX will receive a 5% overriding royalty interest at first production with an option to escalate to either an 8.33% overriding royalty interest or receive a 25% working interest after payout. REX will be fully carried in the drilling costs and Main Pass 221 are expectedexpects an exploratory well to be drilled in the 2004-2005 timeframe. Aspring of 2006. The Vermillion 154 prospect has been farmed out and REX expects the exploratory well to be drilled in July 2008.

Record title interest in the Vermilion 73 and South Marsh Island 247 leases has been assigned to a common third party. The South Marsh Island 247 prospect is in the process of being farmed out, and if successful, a timetable for drilling the prospect will then be established. REX reserves a 5% overriding royalty interest before payout in both prospects. In the Vermilion 15473 prospect, REX also has not been determined at this time. Republic Exploration has sold the NE/4 ofoption after payout to maintain its 5% overriding royalty interest or acquire a 25% working interest in the prospect.

We recently drilled on our West Cameron 133.174 prospect. The remainderwell is availablein the process of being plugged and abandoned. Our 10% working interest share of the dry hole costs for farm-out. Contango Offshore Exploration has granted seismic options on East Breaks 369the well is estimated at $0.8 million.

The farm-out agreement for the Viosca Knoll 75/118/161/116/117/119 prospect was terminated effective June 30, 2005. Our plans, however, are to maintain the remaining leases in the prospect and 370.to evaluate alternative plans that will support potential future drilling of the prospect.

The Minerals Management Service (“MMS”) has implemented a rule on royalty relief for shallow water, deep shelf natural gas production from certain Gulf of Mexico leases. “Deep shelf gas” refers to natural gas produced from depths greater than 15,000 feet in waters of 200 meters or less. Royalty relief is available on the first 15 Bcfbillion cubic feet (“Bcf”) of natural gas production if produced from an interval between 15,000 to less than 18,000 feet. Royalty relief is available on the first 25 Bcf of natural gas production if produced from well depths greater than 18,000 feet. This royalty relief is expected to have a positive impact on the economics of deep gas wells drilled on the shelf of the Gulf of Mexico.

Contango Operators, Inc.

Contango Operators, Inc. (“COI”) is a wholly-owned subsidiary of Contango formed for the purpose of drilling exploration and development wells in the Gulf of Mexico. As part of our strategy, COI will operate and acquire significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, usually under a farm-out agreement with either REX or COE. COI expects to take working interests in these prospects under the same arms-length terms offered to industry third party participants. In the future, and as part of our business strategy, COI will act as the operator on certain offshore prospects.

Current Activities.COI plans to drill and operate two prospects in which our anticipated dry hole working interest commitments will be approximately $5 million per well. In the first exploratory well, the Eugene Island 10 prospect, COI will pay a 35% working interest before casing point election and will have a 18.3% working interest after a casing point election has been made. After a back-in by the farmor of the block, this working interest is reduced to 13.75%. Our partially owned subsidiary, REX, will pay on a 15% working interest before casing point election and will have a 48.75% working interest after a casing point election has been made and after the farmor’s back-in. As of September 7, 2005, COI has secured a drilling rig, consummated a turn-key drilling contract, and expects to begin drilling the initial exploratory well by calendar year-end 2005. COI’s estimated share of drilling costs is $5 million. Net revenue interest to COI and REX after casing point election and after the farmor’s back-in working interest is estimated to be 11% and 39%, respectively.

In the second exploratory well, located in the Grand Isle 72 offshore block, COI will pay a 50% working interest before casing point election and will receive a 25% working interest after casing point election. Our partially owned subsidiary, COE, will be fully carried in the drilling costs prior to casing point election and will have a 50% working interest after a casing point election has been made. As of September 7, 2005, COI has identified and reserved a drilling rig and is in the process of negotiating a turn-key drilling contract. COI expects to begin drilling the initial exploratory well by calendar year-end 2005. COI’s estimated share of drilling costs is $5 million. Net revenue interest to COI and COE after casing point election and after COE’s back-in working interest is estimated to be 20% and 40%, respectively.

COI has submitted plans of exploration with the MMS as the operator of both the Eugene Island 10 and Grand Isle 72 prospects and will be the entity under which Contango will operate these offshore prospects. The plan of exploration for Eugene Island 10 has been approved by the MMS and the plan of exploration for Grand Isle 72 is currently under review by the MMS.

Offshore Properties

Producing Properties. The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico which are producing natural gas or oil as of September 7, 2005:

Farmed-Out Properties. The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico which have been farmed out as of September 7, 2005:

Leases.The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico as of September 15, 2004:7, 2005.

Area/Block		WI			NRI			Acquired		Status
Contango Offshore Exploration (1):
Vermilion 231		100.0	%		80.0	%		May-03		Available for farm-out
Viosca Knoll 167		100.0	%		80.0	%		May-03		Available for farm-out
Eugene Island 209		100.0	%		80.0	%		Jun-03		Available for farm-out
Viosca Knoll 161		100.0	%		80.0	%		Jun-03		Available for farm-out
High Island A16		100.0	%		80.0	%		Nov-03		Available for farm-out
East Breaks 283		100.0	%		80.0	%		Nov-03		Available for farm-out
East Breaks 369		(8	)		(8	)		Nov-03		Subject to seismic option
East Breaks 370		(8	)		(8	)		Nov-03		Subject to seismic option
South Timbalier 191		50.0	%		40.0	%		May-04		Available for farm-out
Grand Isle 63		100.0	%		80.0	%		Jun-04		Available for farm-out
Grand Isle 72		100.0	%		80.0	%		Jun-04		Available for farm-out
Grand Isle 73		100.0	%		80.0	%		Jun-04		Available for farm-out
Ship Shoal 220		50.0	%		40.0	%		May-04		Available for farm-out
South Timbalier 240		50.0	%		40.0	%		May-04		Available for farm-out
Main Pass 221		(9	)		(9	)		Jul-04		Farmed out; drilling expected 2005
Viosca Knoll 118		100.0	%		80.0	%		May-04		Available for farm-out
Vermilion 154		(7	)		(7	)		Jul-04		Farmed out; drilling schedule undetermined
Ship Shoal 358, A-3 well		10.0	%		7.7	%		May-04		Producing
Area/Block		WI			NRI			Acquired		Status
Magnolia Offshore Exploration (1):
Ship Shoal 155		100.0	%		80.0	%		May-02		Available for farm-out
Viosca Knoll 75		100.0	%		80.0	%		May-02		Available for farm-out

Area/Block		WI			Acquired
Contango Offshore Exploration LLC:
Vermilion 231		100.0	%		May-03
Viosca Knoll 167		100.0	%		May-03
Eugene Island 209		100.0	%		Jun-03
High Island A16		100.0	%		Nov-03
East Breaks 283		100.0	%		Nov-03
South Timbalier 191		50.0	%		May-04
Grand Isle 63		100.0	%		Jun-04
Grand Isle 72		100.0	%		Jun-04
Grand Isle 73		100.0	%		Jun-04
Ship Shoal 220		50.0	%		May-04
South Timbalier 240		50.0	%		May-04
Viosca Knoll 75		33.3	%		May-02
Viosca Knoll 167		100.0	%		May-03
Viosca Knoll 161		33.3	%		Jun-03
Viosca Knoll 118		33.3	%		May-04
Viosca Knoll 116		33.3	%		May-05
Viosca Knoll 119		33.3	%		May-05
Viosca Knoll 475		100.0	%		Mar-05
Eugene Island 168		50.0	%		Mar-05
Area/Block		WI			Acquired
Magnolia Offshore Exploration (subjectLLC:
Ship Shoal 155		100.0	%		May-02
Viosca Knoll 75		16.7	%		May-02
Viosca Knoll 161		16.7	%		Jun-03
Viosca Knoll 118		16.7	%		May-04
Viosca Knoll 211		100.0	%		Jun-04
Viosca Knoll 116		16.7	%		May-05
Viosca Knoll 119		16.7	%		May-05

Freeport LNG Development, L.P.

In March 2003, we exercised an option to purchase from Cheniere Energy, Inc.As of June 30, 2005, the Company has invested $3.0 million and owns a 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG Project” and “Freeport LNG”), a limited partnership formed to develop a 1.5 billion cubic feet per day LNG(“Bcf/d”) liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas. The $2.3 million cost to acquire our 10% limited partnership interest was paid as of June 30, 2004, including a final payment of $0.4 million paid in June 2004 upon receipt of Federal Energy Regulatory Commission (“FERC”) approval for the project.

In June 2003, Dow Chemical Company signed an agreement with Freeport LNG for the potential long-term use of the receiving terminal. Under the agreement, Dow had regasification rights to 500 million cubic feet per day beginning with commercial start-up of the facility expected 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 million cubic feet per day of regasification capacity and an option to acquire an additional 250 million cubic feet per day of regasification capacity. Dow has exercised its rights to the full 500 million cubic feet per day of regasification capacity.

In June 2004, FERC issued an Order under Section 3 of the Natural Gas Act authorizing Freeport LNG to site, construct and operate a liquefied natural gas receiving terminal in Freeport, Texas. In September 2004, FERC extended until June 2009 the time Freeport LNG has to put the LNG terminal into service.

In July 2004, Freeport LNG finalized its transaction with ConocoPhillips for the financing, construction and use of the proposed liquefied LNG receiving terminal in Freeport, Texas. ConocoPhillips acquired 1.0 billion cubic feet per dayexecuted a terminal use agreement for 1 Bcf/d of regasification capacity, in the terminal, purchased a 50% interest in the general partner managing the Freeport LNG Projectproject and willagreed to provide substantial construction funding to the venture. This construction funding will be non-recourse to Contango. Dow Chemical has also executed a terminal use agreement for regasification capacity of 500 million cubic feet per day (“MMcf/d”) and, in an unrelated transaction with another limited partner, has purchased a 15% limited partnership interest in Freeport LNG. Freeport LNG and ConocoPhillips are negotiating the engineering, procurement and construction contractis responsible for the terminal. The current management of Freeport LNG will remain in place and will oversee the commercial activities of the partnership, while ConocoPhillips, will manageunder a construction advisory and management agreement, is managing the construction of the facility and oversee its operations.facility.

Although we believe thatIn January 2005, Freeport LNG received its authorization to commence construction of the first phase of its terminal from the Federal Energy Regulatory Commission (the “FERC”) and construction of the 1.5 Bcf/d facility commenced on January 17, 2005. The engineering, procurement and construction contractor is a consortium of Technip USA, Zachry Construction of San Antonio, and Saipem SpA of Italy.

A majority of the Freeport LNG financing will be provided bythrough construction funding throughby ConocoPhillips. Construction has started with a budget, including a significant amount of contingency, of approximately $780 million. ConocoPhillips wehas agreed to lend the project the first $460 million plus 50% of any amount above such an amount (“Tranche A”). Tranche A is estimated at approximately $620 million. Debt service for Tranche A is provided by the terminal use agreement with ConocoPhillips. ConocoPhillips has also agreed to loan the project the remaining 50% of construction funding above $460 million (“Tranche B”). In addition to the $160 million for Tranche B, Freeport LNG has committed to $43 million of work that is not covered by the ConocoPhillips agreements and is therefore a sole obligation of Freeport LNG. Freeport LNG is actively working to obtain third-party funding to replace the ConocoPhillips Tranche B loan, fund the additional commitments noted above (both totaling $203 million) as well as provide pre-funding of some expansion assets (discussed below). Such third-party debt will be secured primarily by payments obligated under the terminal use agreement with Dow Chemical. We do anticipate that we will,may, from time-to-time, be required to provide funds to the project. Moreover, if the plant’s capacity were to be expanded beyond its current anticipated 1.5 Bcf per day, we would likely be requiredproject, and intend to provide our pro rata 10% of any required equity participationparticipation. Currently, if no third-party financing is obtained by Freeport LNG, our 10% share of the project costs not financed under the ConocoPhillips agreement is approximately $4.3 million. Further, once third-party debt is drawn, the Tranche B loan from ConocoPhillips will no longer be available to help secure the funds required for expanding the plant’s capacity.Freeport LNG.

As of June 30, 2005, permitting of a 2.5 Bcf/d expansion is underway bringing the potential size of the facility to approximately 4 Bcf/d. However, Freeport LNG is contractually limited to saleable capacity of 2.65 Bcf/d. As such, the saleable capacity of the facility is expected to increase by approximately 1.15 Bcf/d. Of this expansion capacity, 300 MMcf/d of regasification capacity has been acquired by ConocoPhillips. Also, in January 2005, Freeport LNG executed a 17-year terminal use agreement with MC Global Gas Corporation, a wholly-owned subsidiary of Mitsubishi Corporation. The agreement is for 150 MMcf/d of throughput capacity in the expansion, beginning January 1, 2009. MC Global Gas Corporation has an option to increase the total capacity by an additional 100 MMcf/d, to a total of 250 MMcf/d.

Contango Venture Capital Corporation

In June 2004, our wholly ownedwholly-owned subsidiary, Contango Venture Capital Corporation (“CVCC”), acquired a 32% membership interest in Contango Capital Partnership Management, LLC. Contango Capital Partnership ManagementLLC (“CCPM”). CCPM was formed by us and other investors to invest in the energy venture capital market with a focus on domestically sourced, environmentally preferred energy technologies and to expose us to leading edge technologies and opportunities in alternative energy markets. Our initial cash contribution of $0.5 million is beingwas used to fund the initial overhead for the sourcing and management of energy venture capital investments.investments to be evaluated and made by CCPM. We hold two of sixseven seats on the board of managersdirectors of Contango Capital Partnership Management, LLC.CCPM.

In July 2004, Contango Venture Capital CorporationCVCC committed to invest $0.1 million asin exchange for a limited partnerpartnership interest in Trulite Energy Partners, L.P. Trulite Energy Partners, L.P. is a developerwas an investor and principal shareholder of Trulite Inc. Trulite, Inc. develops lightweight hydrogen generators for fuel cell systems.systems and expects to produce a prototype of a portable fuel cell in 2005. CVCC has since fulfilled all of its $0.1 million commitment to Trulite Energy Partners, L.P. Trulite Energy Partners, L.P. was dissolved in January 2005 and all limited partnership interests in Trulite Energy Partners L.P. were converted into preferred equity shares of Trulite, Inc.

In January 2005, Contango Capital Partners, L.P. was formed for the purpose of investing in the energy venture capital market and formed the Contango Capital Partners Fund, L.P. (the “Fund”).

In January 2005, CVCC contributed all of its preferred and common shares of Trulite, Inc. and Synexus, Inc. to the Fund and also committed to contribute an additional $1.5 million in cash to the Fund. In exchange for these contributions of stock and cash, CVCC received a 25% limited partnership interest in the Fund. The other limited partners of Trulite Energy Partners, L.P., like CVCC, also contributed their preferred and common equity shares of Trulite, Inc, and like CVCC also made cash commitments to the Fund in exchange for limited partnership interests in the Fund.

On January 31, 2005, the Fund was closed to new investment with a total capitalization of $8.2 million in the form of contributed stock, cash, and future cash commitments. CCPM is the general partner and manager of the Fund.

As of June 30, 2005, the Fund owned equity interests in four portfolio alternative energy companies, including Trulite, L.P.Inc., and will likely make additional investments in alternative energy companies. The Fund’s other portfolio companies are Synexus Energy, Inc., Protonex Technology Corp., and Jadoo Power Systems. Synexus Energy Inc. is Contango Capital Partnership Management LLC. Contango Capital Partnership Management LLC assisted Trulite, L.P.a portable and stationary fuel cell integrator developing technology with a lightweight fuel cell stack that will create both portable and stationary power solutions for customers. Protonex Technology Corp. provides long-duration portable and remote power sources with a focus on providing solutions to the U.S. military and supplies complete power solutions and application engineering services to original equipment manufacturers (“OEM”) customers. Jadoo Power Systems develops high energy density power products for the law enforcement, military and electronic news gathering applications.

CVCC’s 25% limited partnership interest in raising $0.5the Fund, as well other limited partners’ interests, were determined by CCPM based on fair market valuations of the portfolio companies’ shares of stock and cash commitments contributed to the Fund and made available at the time of the Fund’s close. The mark-to-market adjustments made by CCPM of each portfolio company were based on an analysis of comparable public and private companies, third party cash contributions, and intervening value enhancement. These mark-to-market adjustments were made to take into consideration value enhancements that had occurred during the period leading up to the Fund’s close, and were warranted based on the portfolio companies’ enhanced commercial viability.

As of June 30, 2005, CVCC had contributed approximately $1 million of seed equity. The proceedsits $1.5 million commitment to the Fund, bringing its total cash investment in alternative energy to approximately $1.5 million.

As of this initial financing will be usedJune 30, 2005, the Company recorded an approximate $0.75 million increase to develop Trulite, L.P.’s technology andour investment resulting primarily from unrealized gains of the Fund as a result of a mark-to-market adjustment that was made due to fund general operations.the increase in the value of our alternative energy investments, bringing our total investment to approximately $2.3 million.

Marketing and Pricing

The Company currently derives its revenue principally from the sale of natural gas. As a result, the Company’s revenues are determined, to a large degree, by prevailing natural gas prices. The Company currently sells the majority of its natural gas on the open market at prevailing market prices. The market price for natural gas is dictated by supply and demand, and the Company cannot accurately predict or control the price it receives for its natural gas.

Price decreases would adversely affect our revenues, profits and the value of our proved reserves. Historically, the prices received for natural gas and oil have fluctuated widely. Among the factors that can cause these fluctuations are:

From time to time, we have entered into hedging arrangements to reduce our exposure to decreases in the prices of natural gas and oil. Hedging arrangements expose us to risk of significant financial loss in some circumstances including circumstances where:

In addition, hedging arrangements limit the benefit we would receive from increases in the prices for natural gas and oil. We cannot assure you that the hedging transactions we enter into will adequately protect us from declines in the prices of natural gas and oil. On the other hand, we may choose not to engage in hedging transactions in the future. As a result, we may be more adversely affected by changes in natural gas and oil prices than our competitors who engage in hedging transactions.

Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if NYMEX natural gas prices spike on the date options settle, our policy is to hedge only through the purchase of puts.

Competition

The Company competes with numerous other companies in virtually all facets of its business. Our competitors in the exploration, development, acquisition and production business include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater financial resources and in-house technical expertise.

Government Regulations

Federal Income Tax.Federal income tax laws significantly affect the Company’s operations. The principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, its domestic “intangible drilling and development costs” and to claim depletion on a portion of its domestic natural gas and oil properties based on 15% of its natural gas and oil gross income from such properties (up to an aggregate of 1,000 Bblsbarrels per day of domestic crude oil and/or equivalent units of domestic natural gas).

Environmental Matters.Domestic natural gas and oil operations are subject to extensive federal regulation and, with respect to federal leases, to interruption or termination by governmental authorities on account of environmental and other considerations such as the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)(“CERCLA”) also known as the “Super Fund Law”. The trend towards stricter standards in environmental legislation and regulation could increase costs to the Company and others in the industry. Natural gas and oil lessees are subject to liability for the costs of clean-up of pollution resulting from a lessee’s operations, and may also be subject to liability for pollution damages. The Company maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident of pollution may also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area.

The Oil Pollution Act of 1990 (the OPA)“OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United StatesU.S. waters. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent the Company’s offshore lease operations affect state waters, the Company may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether these financial responsibility requirements under the OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely affect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico.

The Company’s onshore operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws and regulations, among other things, impose absolute liability on the lessee for the cost of clean-up of pollution resulting from a lessee’s operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a significant impact on the operating costs of the Company, as well as the natural gas and oil industry in general. Federal, state and local initiatives to further regulate the disposal of natural gas and oil wastes are also pending in certain jurisdictions, and these initiatives could have a similar impact on the Company. The Company’s operations are also subject to additional federal, state and local laws and regulations relating to protection of human health, natural resources, and the environment pursuant to which the Company may incur compliance costs or other liabilities.

The Company believes that, in the course of conducting its natural gas and oil operations, the costs attributable to environmental control facilities were not considered material to the Company’s overall operations. For the fiscal year ending June 30, 2005,2006, the Company does not anticipate any material capital expenditures for environmental control facilities.

Other Laws and Regulations.Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company’s properties and to limit the allowable production from the successful wells completed on the Company’s properties, thereby limiting the Company’s revenues.

The MMS administers the natural gas and oil leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The MMS holds a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the MMS changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater extent than other similarly situated producers. At the end of lease operations, oil and gas lessees must plug and abandon wells, remove platforms and other facilities, and clear the lease site sea floor. The MMS requires companies operating on the Outer Continental Shelf to obtain surety bonds to ensure performance of these obligations. Prior to the Company’s decision to act as the operator in the drilling of offshore prospects, the Company was required by the MMS to obtain surety bonds, typically providing $50,000 in coverage per lease, an amount of coverage that ensures a minimum level of performance. As an operator, however, the Company will be required to obtain surety bonds of $200,000 per lease for exploration and $500,000 per lease for developmental activities.

The FERC has embarked on wide-ranging regulatory initiatives relating to natural gas transportation rates and services, including the availability of market-based and other alternative rate mechanisms to pipelines for transmission and storage services. In addition, the FERC has announced and implemented a policy

allowing pipelines and transportation customers to negotiate rates above the otherwise applicable maximum lawful cost-based rates on the condition that the pipelines alternatively offer so-called recourse rates equal to the maximum lawful cost-based rates. With respect to gathering services, the FERC has issued orders declaring that certain facilities owned by interstate pipelines primarily perform a gathering function, and may be transferred to affiliated and non-affiliated entities that are not subject to the FERC’s rate jurisdiction. The Company cannot predict the ultimate outcome of these developments, or the effect of these developments on transportation rates. Inasmuch as the rates for these pipeline services can affect the natural gas prices received by the Company for the sale of its production, the FERC’s actions may have an impact on the Company. However, the impact should not be substantially different on the Company than it will on other similarly situated natural gas producers and sellers.

Government Regulation of LNG Operations.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 the acquisition of certain permits and other authorizations before commencement of construction and operation of an LNG receiving terminal. Failure to comply with such rules, regulations and laws could result in substantial penalties.

In order to site, construct and operate the Freeport LNG receiving terminal, authorization from the FERC under Section 3 of the Natural Gas Act of 1938 (the “NGA”) was required. The FERC permitting process includes detailed engineering and design work, extensive data gathering, preparation and final issuance of an Environmental Impact Statement under the National Environmental Policy Act, and public notices and opportunities for public hearings. Freeport LNG received this authorization in June 2004 to site, construct and operate our proposed LNG receiving terminal. While the Freeport LNG receiving terminal could be in operation as early as June 2007, in September 2004, FERC extended the completion date for the receiving terminal until June 2009.

The Freeport LNG receiving terminal will also be subject to Department of Transportation and Coast Guard regulationshearings relating to:

Freeport LNG received this authorization in June 2004 to site, construct and operate our proposed LNG receiving terminal. In January 2005, the FERC granted Freeport LNG authorization under Section 3 of the NGA to site, construct and operate an LNG receiving terminal and to construct a 9.4 mile pipeline, together

with related facilities, in Brazoria County, Texas. Authorization under Section 3 of the NGA was required because the Freeport LNG facility will be used to import natural gas from a foreign country. The Freeport LNG send-out pipeline will not interconnect with any interstate natural gas pipelines and will not be used to provide interstate transportation service under the NGA.

Other Federal Governmental Permits, Approvals and Consultations.In addition Freeport LNG’sto the FERC authorization under Section 3 of the NGA, the construction and operation of LNG receiving terminals is also subject to additional federal and state permits, approvals and consultations including: Texas Commission on Environmental Quality, U.S. Coast Guard, 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 (the “EPA”) and U.S. Department of Homeland Security and the Advisory Counsel on Historic Preservation.

Environmental Matters.LNG operations are subject to various federal, state and local laws and regulations relating to the protection of the environment, including CERLA.environment. In some cases, these laws and regulations maycould require Freeport LNG to obtain governmental authorizations before Freeport LNG can conductconducting certain activities or may require Freeport LNG to limit certain activities in order to protect endangered or threatened species or sensitive areas. These environmental laws may impose substantial penalties for noncompliance and substantial liabilities for pollution andpollution. As with the industry generally, increase Freeport LNG’scompliance with these laws increases the overall cost of business. Further, environmentalEnvironmental regulations have historically been subject to frequent change. Consequently, we are unable to predict the future costs or other future impacts of environmental regulations. Environmental laws that may affect our operations include:

CERCLA

CERCLA imposes liability, without regard to fault, on certain classes of persons who are considered to be responsible for the spill or release of a hazardous substance into the environment. Potentially liable persons include the owner or operator of the site where the release occurred and persons who disposed or arranged for the disposal of hazardous substances at the site. Under CERCLA, responsible persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment; damages to natural resources; and the costs of certain health studies.

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

Clean Air Act

LNG operations may be subject to the federal Clean Air Act (the “CAA”) and comparable state and local laws. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have been developing regulations onto implement these requirements. Freeport LNG may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing other air emission-related issues.

Clean Water Act

LNG operations are also subject to the federal Clean Water Act (the “CWA”) and analogous state and local laws. Pursuant to certain requirements of the CWA, the EPA has adopted regulations concerning discharges of 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. In addition, our future operations.operations, including construction of LNG receiving terminals, in areas deemed to be wetlands, or which otherwise involve discharges of dredged or fill material into navigable waters of the United States, may be subject to Army Corps of Engineers permitting requirements.

Hazardous Waste

The federal Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes govern the disposal of “hazardous wastes.” In the event any hazardous wastes are generated in connection with LNG operations, Freeport LNG may be subject to regulatory requirements affecting the handling, transportation, storage and disposal of such wastes.

Endangered Species

LNG operations may be restricted by requirements under the Endangered Species Act (the “ESA”) 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.

Employees

We have foursix employees, all of whom are full time. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We are dependent on our alliance partners in the areas of geological and geophysical services andfor prospect generation, evaluation and prospect leasing. As a working interest owner, we rely on outside operators to drill, produce and market our natural gas and oil for our onshore prospects and certain offshore prospects where we are a non-operator. In the offshore prospects where we are the operator, we rely on a turn-key contractor to drill and will rely on independent contractors to produce and market our natural gas and oil. In addition, we utilize the services of independent contractors to perform field and on-site drilling and production operation services.

Directors and Executive Officers

The following table sets forth the names, ages and positions of our directors and executive officers:

Kenneth R. Peak.Mr. Peak has been Chairman and CEO of Contango since its formation in September 1999. Prior to September 1999, Mr. Peak was President of Peak Enernomics, Incorporated, a company engagedentered the energy industry in consulting activities to the natural gas and oil industry. Mr. Peak’s energy career began in 19731972 as a commercial banker and held a variety of financial and executive positions in First Chicago’s energy group. In 1980, Mr. Peak became Treasurer of Tosco Corporation and in 1982 Chief Financial Officer of Texas International Company. Mr. Peak’s tenure included serving as President of TIPCO, the domestic operating subsidiary of Texas International Company’s oil and gas operations. Mr. Peak has also served as Chief Financial Officer of Forest Oil and as an investment banker with Howard Weil.industry prior to starting Contango in 1999. Mr. Peak served as an officer in the U.S. Navy from 1968 to 1971. Mr. Peak received a BS in physics from Ohio University and aan MBA from Columbia University. He currently serves as a director of Patterson-UTI Energy, Inc., a provider of onshore contract drilling services to exploration and production companies in North America.

William H. Gibbons. Mr. Gibbons joined Contango in February 2000 as Treasurer and was appointed Vice President and Treasurer in November 2000. His energy career began with Houston Oil & Minerals Corporation, where he was Treasurer from 1975 to 1981. From 1981 to 1983, he served as Vice President-Finance and Administration for Guardian Oil Company. From 1983 to 1986 and 1990 to 1998, Mr. Gibbons provided financial consulting services to domestic and international oil companies, including a five-year financing assignment with Walter International, Inc. (1991-1996). He also has served as Director of Acquisitions for Service Corporation International (1986-1990) and Treasurer of Packaged Ice, Inc. (1998-2000). Mr. Gibbons received a BA in Business Administration from Duke University and a MBA in Finance from Tulane University.

Lesia Bautina. Ms. Bautina joined Contango in November 2001 as Controller and was appointed Vice President and Controller in August 2002. In July 2005, Ms. Bautina was promoted to Senior Vice President. Prior to joining Contango, Ms. Bautina worked as an auditor for Arthur Andersen LLP from 1997 to 2001. Her primary experience is accounting and financial reporting for exploration and production companies. Ms. Bautina received a degree in History from the University of Lvov in the Ukraine in 1990 and a BBA in Accounting in 1996 from Sam Houston State University, where she graduated with honors. Ms. Bautina is a Certified Public Accountant and member of the Petroleum Accounting Society of Houston.

Marc Duncan. Mr. Duncan joined Contango Oil & Gas Company in June 2005 as President and Chief Operating Officer of Contango Operators, Inc. Mr. Duncan has over 25 years of experience in the energy industry and has held a variety of domestic and international engineering and senior-level operations management positions relating to natural gas and oil exploration, project development, and drilling and production operations. Prior to joining Contango, Mr. Duncan served as senior operations manager for USENCO International, Inc. from 2000-2004 and as a senior project and drilling engineer for Hunt Oil Company from 2004-2005. He holds an MBA in Engineering Management from the University of Dallas, an MEd from the University of North Texas and a BS in Science and Education from Stephen F. Austin University.

David L. Holcombe.Mr. Holcombe joined Contango in November 2004 as Assistant Treasurer. Prior to joining Contango, Mr. Holcombe spent three years as a financial consultant preceded by a career in treasury, international finance, mergers and acquisitions and project finance for several energy companies. From 2000 to 2001, Mr. Holcombe was Manager, Corporate Finance for Ocean Energy, Inc. From 1998 to 2000, Mr. Holcombe worked as a senior financial analyst for EGL Eagle Global Logistics, Inc. and from 1996 to 1998 was a financial analyst with the Pennzoil Company. Mr. Holcombe’s energy career began with Transco Energy Company, where he was an environmental engineer from 1990-1994. Mr. Holcombe received an MBA from Rice University in 1996 and a B.S. in Mechanical Engineering from Louisiana State University in 1990.

Jay D. Brehmer. Mr. Brehmer has been a director of Contango since October 2000. Mr. Brehmer is Managing Director of Catalina Capital Advisors LP, a boutique financial advisory, merger and acquisition investment bank. From November 2002 until August 2004, he advised various energy and energy-related companies on corporate finance and merger and acquisition activities through Southplace, LLC. From May 1998 until November 2002, Mr. Brehmer was responsible for structured-finance energy related transactions at Aquila Energy Capital Corporation. Prior to joining Aquila, Mr. Brehmer founded Capital Financial Services, which provided mid-cap companies with strategic merger and acquisition advice coupled with prudent financial capitalization structures. His corporate finance industry experience also includes five years from 1990 until

1995 as Vice President of the investment banking subsidiary of Mutual of Omaha. He was responsible for the development and completion of all aspects of both private and public securities transactions. From 1985 until 1990, he was Vice President-Corporate Finance and Operations Manager for R. G. Dickinson & Company, a full service regional brokerage firm, where he created and managed the financial modeling of various public and private securities transactions. Mr. Brehmer holds a BBA from Drake University in Des Moines, Iowa.

Joseph S. Compofelice. Mr. Compofelice has been a director of Contango since 2002. Mr. Compofelice is Managing Director of Catalina Capital Advisors LP, a boutique financial advisory, merger and acquisition investment bank. He is the Chairman of the Board of Trico Marine Services, Inc., a provider of marine support vessels serving the international natural gas and oil industry, and a member of the Board of Advisors of Courtland Inc., a privately held investment management firm. From 2001 to 2003, Mr. Compofelice was Chief Executive Officer of Aquilex Services Corp., a provider of services and equipment to the power generation and heavy processing industries. For the period 1998 through 2002, Mr. Compofelice was Chairman and CEO of CompX International Inc., a producer of hardware for the office furniture industry. From 1994 through 1997, Mr. Compofelice was a Director and CFO of NL Industries Inc., a chemical producer, and Director and CFO of TIMET, a producer of titanium metal principally for the aerospace industry. Mr. Compofelice received his BS at California State University at Los Angeles and his MBA at Pepperdine University.

Darrell W. Williams. Mr. Williams has been a director of Contango since 1999. HeMr. Williams is an international business consultant working through the firmManaging Director of WilliamsCatalina Capital Advisors LP, a boutique financial advisory, merger and Associates, Inc.acquisition investment bank. From 1993 until 2002, Mr. Williams was associated with the German firm of Deutag Drilling, GmbH in both marketing and operations positions. In September 1996, he was transferred to Germany and served as Managing Director of Deutag International, the subsidiary which had responsibility for all drilling operations outside of Europe. Prior to joining Deutag, Mr. Williams was in senior executive positions with Nabors Drilling (1988-1993), Pool Company (1985-1988), Baker Oil Tools (1980-1983), SEDCO (1970-1980), Tenneco (1966-1970), and Humble Oil (1964-1966). Mr. Williams graduated from West Virginia University with a degree in Petroleum Engineering in 1964. Mr. Williams is past Chairman of the Houston Chapter of International Association of Drilling Contractors, a life member of the Society of Petroleum Engineers and a registered professional engineer in Texas. He also serves as a business advisor of privately held Porta-Kamp, a company engaged in the design and manufacturing of prefabricated housing and camps.

Directors of Contango serve as members of the board of directors until the next annual stockholders meeting, until successors are elected and qualified or until their earlier resignation or removal. Officers of Contango are elected by the board of directors and hold office until their successors are chosen and qualified, until their death or until they resign or have been removed from office. All corporate officers serve at the discretion of the board of directors. During the fiscal year ended June 30, 2004,2005, each outside director received a quarterly retainer of $3,000$5,000 and a quarterly stock option grant to purchase 3,000 shares of common stock. Effective July 1, 2004, the quarterly retainer for each outside director was increased to $5,000. Each outside director also receives a $1,000 cash payment for each board meeting and separately scheduled Audit Committee meeting attended. The Chairman of the Audit Committee receives an additional quarterly stock option grant to purchase 1,500 shares of common stock. There are no family relationships between any of our directors or executive officers.

Corporate Offices

We lease our corporate offices at 3700 Buffalo Speedway, Suite 960, Houston, Texas 77098. Effective June 1, 2004, we increased our office space from 2,850 square feet to 5,377 square feet. Our agreement provides for a monthly rental of $9,970 per month through October 2006.

Code of Ethics

We adopted a Code of Ethics for senior management in December 2002. A copy of our Code of Ethics is filed as an exhibit to this Form 10-K and is also available on our Website atwww.contango.comwww.contango.com..

Risk Factors

In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating Contango.the Company. An investment in Contango will bethe Company is subject to risks inherent in our business. The trading price of the shares of Contango will bethe Company is affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in Contangothe Company may decrease, resulting in a loss. The risk factors listed below are not all inclusive.

We have no ability to control the prices that we receive for natural gas and oil. Natural gas and oil prices fluctuate widely, and low prices could have a material adverse effect on our revenues, profitability and growth.

Our revenues, profitability and future growth will depend significantly on natural gas and crude oil prices. Prices received also will affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and will affect our ability to raise additional capital. Lower prices may also affect the amount of natural gas and oil that we can economically produce. Factors that can cause price fluctuations include:

We depend on the services of our chairman, chief executive officer and chief financial officer, and implementation of our business plan could be seriously harmed if we lost his services.

We depend heavily on the services of Kenneth R. Peak, our chairman, chief executive officer, and chief financial officer. We do not have an employment agreement with Mr. Peak, and the proceeds from a $10.0 million “key person” life insurance policy on Mr. Peak may not be adequate to cover our losses in the event of Mr. Peak’s death.

We are highly dependent on the technical services provided by our alliance partners and could be seriously harmed if our alliance agreements were terminated.

Because we have only six employees, none of whom are geoscientists or petroleum engineers, we are dependent upon alliance partners for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. Highly qualified explorationists and engineers are difficult to attract and retain. As a result, the loss of the services of one or more of our alliance partners could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, the loss by our alliance partners of certain explorationists could have a material adverse effect on our operations as well.

Our ability to successfully execute our business plan is dependent on our ability to obtain adequate financing.

Our business plan, which includes participation in 3-D seismic shoots, lease acquisitions, the drilling of exploration prospects and producing property acquisitions, has required and will require substantial capital expenditures. We may require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. In particular, our credit facility imposes limits on our ability to borrow under the facility based on adjustments to the value of our hydrocarbon reserves, and our credit facility and the terms of our outstanding preferred stock limitlimits our ability to incur additional indebtedness. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.

We lack experience as Operator in drilling high pressure wells in the Gulf of Mexico.

Contango Operators, Inc. (“COI”) is a wholly-owned subsidiary of the Company, formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico and is a new element of our business strategy. COI has submitted a plan of exploration with the Minerals Management Service (“MMS”) as the designated operator for both the Grand Isle 72 and Eugene Island 10 prospects and will be the entity under which Contango will operate these offshore prospects. The plan of exploration for Eugene Island 10 has been approved by the MMS and approval of the plan of exploration for Grand Isle 72 is currently pending. Although as a company we have taken working interests in offshore prospects, we have previously never assumed the role of operator.

Drilling activities are subject to numerous risks, including the risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. The Company’s drilling operations may be curtailed, delayed, canceled or negatively impacted as a result of numerous factors, including inexperience as an operator, title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and fabrication yards. In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for drilling rigs, drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the offshore oil and gas industry in particular. This may lead to difficulty and delays in consistently obtaining certain services and equipment from vendors, obtaining drilling rigs and other equipment at favorable rates and scheduling equipment fabrication at factories and fabrication yards. This, in turn, may lead to projects being delayed or

experiencing increased costs. The cost of drilling, completing, and operating wells is often uncertain, and we cannot assure that new wells will be productive or that we will recover all or any portion of our investment. The risk of significant cost overruns, curtailments, delays, inability to reach our target reservoir and other factors detrimental to drilling and completion operations may be higher due to our inexperience as an operator.

The construction of our LNG receiving terminal in Freeport, Texas is subject to various development and completion risks.

We own a 10% limited partnership interest in a proposedthe Freeport LNG receiving facility to be builtthat is being constructed in Freeport, Texas. The LNG project received FERC approval from the Federal Energy Regulatory Commission (the “FERC”) in June 2004. On January 11, 2005, Freeport LNG received its authorization to commence construction of the first phase of its terminal from the FERC. Construction of the 1.5 Bcf/d facility commenced on January 17, 2005. Freeport LNG is seeking an additional order from the FERC that would authorize the construction of an expansion that would increase the capacity at its currently permitted 1.5 Bcf/d Freeport LNG terminal to 2.6 Bcf/d. The LNG receiving facility however, remains in development stage andis subject to development risk such as permitting, cost overruns and delays. Key factors that may affect the completion of the LNG receiving terminal include, but are not limited to: timely issuance of necessary additional permits, licenses and approvals by governmental agencies and third parties; sufficient financing; unanticipated changes in market demand or supply; competition with similar projects; labor disputes; site difficulties; environmental conditions; unforeseen events, such as hurricanes, explosions, fires and product spills; delays in manufacturing and delivery schedules of critical equipment and materials; resistance in the local community; local and general economic conditions; and commercial arrangements for pipelines and related equipment to transport and market LNG.

If completion of the LNG receiving facility is delayed beyond the estimated development period, the actual cost of completion may increase beyond the amounts currently estimated in our capital budget. A delay in completion of the LNG receiving facility would also cause a delay in the receipt of revenues projected from operation of the facility, which may cause our business, results of operations and financial condition to be substantially harmed.

If we are not able to fund or finance our 10% ownership in the LNG receiving facility in Freeport, Texas, we may lose our 10% investment in the projectproject..

In December 2003, ConocoPhillips and Freeport LNG signed an agreement providing for ConocoPhillips’ participation in Freeport LNG’s project to build the receiving terminal. ConocoPhillips will acquire one billion cubic feet per day1 Bcf/d of capacity in the terminal for its use, obtainuse. ConocoPhillips purchased a 50% interest in the general partner of Freeport LNG and, as noted above, has agreed to provide substantially all of the construction funding presently estimated in excess of $500 million.funding. Without such financing or upon any significant shortfall in project funding, it is unlikely that we wouldmay not have the financial resources to fund our 10% ownership share of construction costs. If we are unable to financefund our share of the project costs or if the project is unable to secure third-party project financing, we could lose our investment in the project.

Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect our production and cash flows.

Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows would be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Further, substantially all of our reserves are proved developed producing. Accordingly, we do not have significant opportunities to increase our production from our existing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present values of our reservesreserves..

The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report.

In order to prepare these estimates, our independent third party petroleum engineer must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of natural gas and oil reserves are inherently imprecise.

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in this report. In addition, estimates of our proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control. Some of the producing wells included in our reserve report have produced for a relatively short period of time as of June 30, 2004.2005. Because some of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a more lengthy production history.

You should not assume that the pre-tax net present value of our proved reserves prepared in accordance with SEC guidelines referred to in this report is the current market value of our estimated natural gas and oil reserves. We base the pre-tax net present value of future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices, costs, taxes and the volume of produced reserves may differ materially from those used in the pre-tax net present value estimate.

Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect our production and cash flows. Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows would be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Further, substantially all of our reserves are proved developed producing. Accordingly, we do not have significant opportunities to increase our production from our existing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.

We depend on the services of our chairman, chief executive officer and chief financial officer, and implementation of our business plan could be seriously harmed if we lost his services. We depend heavily on the services of Kenneth R. Peak, our chairman, chief executive officer, and chief financial officer. We do not have an employment agreement with Mr. Peak, and the proceeds from a $10.0 million “key person” life insurance policy on Mr. Peak may not be adequate to cover our losses in the event of Mr. Peak’s death.

We are highly dependent on the technical services provided by our alliance partners and could be seriously harmed if our alliance agreements were terminated. Because we have only four employees, none of whom are geoscientists or petroleum engineers, we are dependent upon alliance partners for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. Highly qualified explorationists and engineers are difficult to attract and retain in this industry. As a result, the loss of the services of one or more of our alliance partners could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, the loss by our alliance partners of certain explorationists or engineers could have a material adverse effect on our operations as well.

We rely on the accuracy of the estimates in the reservoir engineering reports provided to us by our outside engineers.

We have no in house reservoir engineering capability, and therefore rely on the accuracy of the periodic reservoir reports provided to useus by our outsideindependent third party reservoir engineers. If those reports prove to be inaccurate, our financial reports could have material misstatements. Further, we use the reports of our independent reservoir engineers in our financial planning. If the reports of the outside reservoir engineers prove to be inaccurate, we may make misjudgments in our financial planning.

Exploration is a high risk activity, and our participation in drilling activities may not be successful.

Our future success will largely depend on the success of our exploration drilling program. Participation in exploration drilling activities involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our drilling activities would materially and adversely affect our future cash flows and results of operations.

In addition, as a “successful efforts” company, we choose to account for unsuccessful exploration efforts (the drilling of “dry holes”) and seismic costs as a current expense of operations, which immediately impacts our earnings. Significant expensed exploration charges in any period would materially adversely affect our earnings for that period and cause our earnings to be volatile from period to period.

The natural gas and oil business involves many operating risks that can cause substantial losses.

The natural gas and oil business involves a variety of operating risks, including:

If any of these events occur, we could incur substantial losses as a result of:

Offshore operations also are subject to a variety of operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce the funds available for exploration, development or leasehold acquisitions, or result in loss of properties.

If we were to experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, any one of which could adversely affect our ability to conduct operations. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.

We may not be able to maintain adequate insurance in the future at rates we consider reasonable, and particular types of coverage may not be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

We may face operational and financial risks associated with foreign exploration and development. We recently unsuccessfully drilled a well in the Aquitaine Basin in southwestern France. We have no future drilling plans in France If, however, we pursue further activities in France or elsewhere outside of the United States, we will face operational and financial risks associated with foreign exploration and development.

Not hedging our production may result in losses.

Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if NYMEX natural gas prices spike on the date options settle, our policy is to hedge only through the purchase of puts. By not hedging our production, we may be more adversely affected by declines in natural gas and oil prices than our competitors who engage in hedging arrangements.

Our ability to market our natural gas and oil may be impaired by capacity constraints on the gathering systems and pipelines that transport our natural gas and oil. Most

All of our natural gas and a substantial portion of our oil is transported through gathering systems and pipelines, which we do not own. Transportation capacity on gathering systems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to these facilities or due to capacity being utilized by other natural gas

or oil shippers that may have priority transportation agreements. If the gathering systems or our transportation capacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition and results of operations.

Our natural gas and oil production is concentrated in south Texas and is sold to a limited number of purchasers.Substantially all of our current production comes from wells drilled in south Texas. This production is gathered on a single pipeline and is sold on a spot market basis to one purchaser. Any disruption of our pipeline or marketing arrangements or financial difficulties with any purchaser, or alternative marketing sources, could have an adverse effect on our ability to market our natural gas and oil production. Additionally, if a purchaser suffered financial difficulties, we might not be able to collect receivables from the purchaser.

We have no assurance of title to our leased interests.

Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is not to incur the expense of retaining lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of our alliance partners to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. We have no assurance, however, that any such deficiencies have been cured by the operator of any such wells. It does happen, from time to time, that the examination made by the title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect. It may also happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.

Competition in the natural gas and oil industry is intense, and we are smaller and have a more limited operating history than most of our competitors.

We compete with a broad range of natural gas and oil companies in our exploration and property acquisition activities. We also compete for the equipment and labor required to operate and to develop these properties. Most of our competitors have substantially greater financial resources than we do. These competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties. Further, they may be able to evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have been operating for a much longer time than we have and have substantially larger staffs. We may not be able to compete effectively with these companies or in such a highly competitive environment.

We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment. Failure to comply with such rules and regulations could result in substantial penalties and have an adverse effect on us. These laws and regulations may:

Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain only limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Moreover, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability, or we may be required to cease production from properties in the event of environmental damages. These laws and regulations have been changed frequently in the past. In general, these changes have imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated factual developments could cause us to make environmental expenditures that are significantly different from those we currently expect. Existing laws and regulations could be changed and any such changes could have an adverse effect on our business and results of operations.

We cannot control the activities on properties we do not operateoperate..

Other companies currently operate all of the properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including:

Acquisition prospects are difficult to assess and may pose additional risks to our operations.

We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers favorable. In particular, we expect to pursue acquisitions that have the potential to increase our domestic natural gas and oil reserves. The successful acquisition of natural gas and oil properties requires an assessment of:

In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are necessarily inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.

Future acquisitions could pose additional risks to our operations and financial results, including:

We do not currently intend to pay dividends on our common stock.

We have never declared or paid a dividend on our common stock and do not expect to do so in the foreseeable future. Our current plan is to retain any future earnings for funding growth, and, therefore, holders of our common stock will not be able to receive a return on their investment unless they sell their shares.

Anti-takeover provisions of our certificate of incorporation, bylaws and Delaware law could adversely effect a potential acquisition by third parties that may ultimately be in the financial interests of our stockholders.

Our certificate of incorporation, bylaws and the Delaware General Corporation Law contain provisions that may discourage unsolicited takeover proposals. These provisions could have the effect of inhibiting fluctuations in the market price of our common stock that could result from actual or rumored takeover attempts, preventing changes in our management or limiting the price that investors may be willing to pay for shares of common stock. These provisions, among other things, authorize the board of directors to:

Our common stock is thinly traded.

Contango has approximately 1314.7 million shares of common stock outstanding, held by approximately 5.5115 holders of record. Approximately 2.6 million shares of which are owned by directors officers and affiliates. We have fewer than 3,000 stockholders, andofficers. Since our daily trading volumecommon stock is frequently less than 10,000 shares. Thethinly traded, the purchase or sale of relatively small common stock positions may result in disproportionately large increases or decreases in the price of our common stock.

Available Information

General information about us can be found on our Website at www.contango.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our Website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission.

Item 2.Description of Properties

Production, Prices and Operating Expenses

The following table presents information regarding the production volumes, average sales prices received and average production costs associated with our sales of natural gas and oil for the periods indicated. Oil and condensate are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil or condensate is the energy equivalent of six Mcf of natural gas.

Development, Exploration and Acquisition Capital Expenditures

The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated:

Drilling Activity

The following table shows our drilling activity for the periods indicated. In the table, “gross” wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our working interest in such wells.

Exploration and Development Acreage

Our principal natural gas and oil properties consist of natural gas and oil leases. The following table indicates our interests in developed and undeveloped acreage as of June 30, 2004:2005:

Included in the 93,207178,796 gross and 83,70481,392 net offshore Gulf of Mexico acres shown in the table above are the beneficial interests Contango Oil & Gas Company has in the offshore acreage owned by its partially owned subsidiaries. The above table includes (i) our 33.3% interest in Republic Exploration’s 92,094 gross offshoreExploration LLC’s 83,521 net undeveloped acres, (83,520 net undeveloped acres), (ii) our 66.7% interest in Contango Offshore Exploration 5,000 gross offshoreLLC’s 333 net developed acres (500and in 66,128 net undeveloped acres) and in 78,194 gross offshore undeveloped acres, (73,194 net undeveloped acres), and (iii) our 50% interest in Magnolia Offshore Exploration’s 10,760Exploration LLC’s 15,560 net undeveloped acres. In addition, the Company holds royalty interests in approximately 63,363 gross offshore undeveloped acres (10,760(3,118 net undeveloped acres). and 10,182 gross developed acres (224 net developed acres), both offshore in the Gulf of Mexico and onshore along the Gulf Coast.

Productive Wells

The following table sets forth the number of gross and net productive natural gas and oil wells in which we owned an interest as of June 30, 2004:2005:

Natural Gas and Oil Reserves

The following table presents our estimated net proved natural gas and oil reserves and the pre-tax net present value of our reserves at June 30, 2004,2005, based on a reserve report generated by W.D. Von Gonten & Co. The pre-tax net present value is not intended to represent the current market value of the estimated natural gas and oil reserves we own.

The pre-tax net present value of future cash flows attributable to our proved reserves prepared in accordance with SEC guidelines as of June 30, 20042005 was based on $5.90$7.08 per MMbtumillion British thermal units (“MMbtu”) for natural gas at the Houston Ship Channel (which equated to a NYMEX price of $6.16 per MMbtu) and to a NYMEX oil price of $37.05$56.50 per barrel of oil at the West Texas Intermediate Posting, in each case before adjusting for basis, transportation costs and BtuBritish thermal unit (“Btu”) content. For further information concerning the present value of future net cash flows from these proved reserves, see “Supplemental Oil and Gas Disclosures”.

The process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our third party engineers must project production rates, estimate timing and amount of development expenditures, analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of all of this data can vary. Therefore, estimates of natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from estimates. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.

It should not be assumed that the pre-tax net present value is the current market value of our estimated natural gas and oil reserves. In accordance with requirements of the Securities and Exchange Commission, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Item 3.Legal Proceedings

As of the date of this Form 10-K, we are not a party to any legal proceedings, and we are not aware of any proceeding contemplated against us.

Item 4.Submission of Matters to a Vote of Security Holders

During the quarter ended June 30, 2004,2005, no matters were submitted to a vote of security holders.

PART II

Item 5.Market for Registrant’s Common Equity and Related Stockholder Matters

Our common stock was listed on the American Stock Exchange in January 2001 under the symbol “MCF”. The table below shows the high and low closing prices of our common stock for the periods indicated.

On September 15, 2004,7, 2005, the closing price of our common stock on the American Stock Exchange was $6.40$11.34 per share, and there were 12,977,36614,714,471 shares of Contango common stock outstanding, held by 137approximately 115 holders of record.

We have not declared or paid any dividends on our shares of common stock and do not currently anticipate paying any dividends on our shares of common stock in the future. Currently, except for the regular dividends that we pay on our Series C,preferred stock, our plan is to retain any future earnings for use in the operations and expansion of our natural gas and oil exploration business and as needed in our LNG and alternative energy activities. Our credit facility currently prohibits us from paying any cash dividends on our common stock. The credit facility does, however, permit the payment of stock dividends on our common stock. Any future decision to pay dividends on our common stock will be at the discretion of our board and will depend upon our financial condition, results of operations, capital requirements, and other factors our board may deem relevant.

On December 12, 2003,July 15, 2005, we sold $8.0$10.0 million of our Series CD preferred stock to a group of private institutional investors. The sale of the Series CD preferred stock was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder, as a transaction not involving a public offering. The Series CD preferred stock is perpetual and cumulative, is senior to our common stock and is convertible at any time into shares of our common stock at a price of $6.00$12.00 per share. The dividend on the Series CD preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per annum. We used the net proceeds of this offering to repay indebtedness under our bank revolving credit facility. We intend to use the additional funds made available under our bank credit facility, together with cash flow from operations, to fund natural gas and oil exploration, development and production, to fund offshore lease acquisitions, to fund 3-D seismic shoots and acquisitions,net proceeds to fund our investment inFayetteville Shale play, as well as our proposedoffshore Gulf of Mexico deep shelf exploration program, to fund any needed commitments to Freeport Texas LNG receiving terminal

Development, LP (“Freeport LNG”) and the Contango Capital Partners Fund LP (the “Fund”), and for working capital and general corporate purposes. We have filed a shelf registration

statement with the Securities and Exchange Commission, which has become effective, covering the 1,333,328833,330 shares of common stock issuable upon conversion of the Series D preferred stock.

On July 19, 2005, we exercised our mandatory conversion rights pursuant to the terms of our Series C preferred stock, an additional 1,217,685and converted all of the 1,400 shares of our Series C preferred stock issued and outstanding at that time into 1,166,662 shares of common stock that are issuable upon the exercise of certain stock options and warrants and 200,000stock. The outstanding shares of common stock that may be issuable as a result of payment of the Series C preferred stock dividends in kind.

During the fiscal year ended June 30, 2004, noprior to their conversion, had a face value of $7 million, and paid a 6.0% per annum quarterly cash dividend. The shares of common stock were issued to employees or consultants.upon conversion of the Series C preferred stock are registered with the Securities and Exchange Commission.

Item 6.Selected Financial Data