Index to Financial Statements

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, 20052006

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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 a large accelerated filer, an accelerated filer, (as definedor a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act).    YesExchange Act. (check one):

Large Accelerated Filer  ¨    Accelerated Filer  x    NoNon-Accelerated Filer  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.):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 7,December 31, 2005, was $137,420,706.$133,853,434. As of September 7, 2005,August 31, 2006, there were 14,714,47115,015,835 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.

Index to Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K FOR THE FISCAL ENDED JUNE 30, 20052006

TABLE OF CONTENTS

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Some of the statements made in this report 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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Index to Financial Statements

You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this 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 report or to reflect the occurrence of unanticipated events. See the information under the heading “Risk Factors��Factors” referred to on page 1918 of this report 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”, “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.

PART I

Item 1.Business

Overview

Contango is a Houston-based, independent natural gas and oil company. The Company’s core business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico and onshore alongin the Gulf Coast. As a recent addition toArkansas Fayetteville Shale. Contango Operators, Inc. (“COI”), our business, we will begin actingwholly-owned subsidiary, acts as an operator on certain offshore prospects through our wholly-owned subsidiary, Contango Operators, Inc. (“COI”).prospects. The Company also owns a 10% interest in a limited partnership formed to develop an LNG receiving terminal in Freeport, Texas, and holds investments in the alternative energy venture capital market with a focuscompanies focused on commercializing 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 generated by our alliance partners. We depend on our alliance partners for prospect generation expertise. Our four alliance partners, Juneau Exploration, L.P. (“JEX”), and 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 certain exploration prospects, including our onshore Arkansas Fayetteville Shale prospect area as well as twoand offshore Gulf 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.Mexico prospects. 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$1.0 million. Our estimated cost commitment couldCOI drills and operates our offshore prospects. Should we be significantly larger ifsuccessful in any of our offshore prospects, we encounter difficultly in drilling these wells.will incur additional costs to complete development and bring the discovery to producing status.

Operating in the Gulf of Mexico.Contango Operators, Inc. (“COI”) is a wholly-owned subsidiary of the Company,COI was formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico and is a new element of our business strategy.Mexico. COI will operate for the first time and will drill twohas drilled four exploration wells in the Gulf of Mexico.Mexico, of which two were successful, and is currently drilling one additional exploration well. This represents ana significant increase in the risk profile of the Company since the Company has never before operated. COI willlimited operating experience. Our estimated drilling costs could be the entity under which Contango will operate selectivesignificantly higher if we encounter difficultly in drilling offshore prospects.wells.

Negotiated acquisitions of proved properties.Arkansas Fayetteville Shale.We have made a major commitment to our Arkansas Fayetteville Shale program and this commitment is expected to continue to seek negotiated acquisitionsgrow as we participate in the drilling of producing properties based on our viewhundreds of gross exploration/development wells over the pricing cycles of natural gas and oil and available reserve exploitation opportunities. Since January 1, 2002, we have acquired approximately 14 billion cubic feet equivalent (“Bcfe”) of proved developed producing reserves of natural gas and oil for approximately $26 million.next five to ten years.

Sale of proved properties. From time-to-time as part of our business strategy, we have sold and in the future may continue to 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 September 2003, the Company completed the sale of certain reserves in Brooks County, Texas for $5.0 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 Republic Exploration, LLC (“REX”), our partially owned subsidiary, sold their 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$80.0 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.

Index to Financial Statements

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

Structuring transactions to minimize front-end investmentsshare risk. We seek to maximize returns on capital by minimizing our up-front investments in acreage, seismic data and prospect generation whenever possible. We want ourOur alliance partners to share in boththe upfront costs and 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.prospects.

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%26% of our common stock. In addition, our alliance partners co-invest in prospects that they recommend to us.

Exploration Alliances with JEX Alta, Ameritex and CoastlineAlta

Alliance with JEX.JEX is 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. JEX focuses exclusively on the Gulf of Mexico, and generates offshore exploration prospects via our affiliated companies, REX andRepublic Exploration, LLC (“REX”), Contango Offshore Exploration, LLC (“COE”) and Magnolia Offshore Exploration LLC (“MOE”) (see “Offshore Gulf of Mexico Exploration Joint Ventures” below).

Alliance with Alta. Alta 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 oura disproportionate share of seismic and lease costs, with Alta Resources generally receiving a negotiated overriding royalty interest (“ORRI”) 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 receiving a carried working interest to casing point. Our annual geological and geophysical cost for this prospect generation effort is approximately $80,000.

Alliance with Coastline.Coastline is a private company engaged in domestic, onshore natural gas and oil exploration and production. 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.

Onshore Exploration and Properties

JEX Activities

JEX is focused on prospect generation via our affiliated offshore Gulf of Mexico exploration companies. See “Offshore Gulf of Mexico Exploration and Joint Ventures”.

Alta Activities

Arkansas Fayetteville Shale

In October 2003, Contango and Alta completed a 3-D seismic shoot covering approximately 40 square miles in southern Duval County, Texas. Using this data, Contango and Alta successfully drilled two Queen City prospects that commenced production in September 2004. In October 2004, we participated with Alta 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 well located in Matagorda County, Texas. The dry hole cost was approximately $1.4 million, of which our share was approximately $0.6 million.

In 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 producing commercial quantities of natural gas and oil.

In January 2005, Contango and Alta elected to participate in three exploratory wells 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 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 75% share of the dry hole costs for these two remaining wells is estimated to be $1.8 million.

In March 2005, Contango, Alta and Altaanother private company (the “Alta Group”) entered into a Participation Agreement to acquire natural gas, oil, and mineral leases in the Arkansas Fayetteville Shale play area located in Pope, Van Buren, Conway, Faulkner, Cleburne, and White Counties, Arkansas. Under the Participation Agreement, we agreed to incur 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, 2005August 31, 2006, the Alta hadGroup has acquired or received commitments on approximately 32,00044,000 net mineral acres at a cost of approximately $6.9$12.0 million. OurContango has a 70% share of the acquisition costs is about $4.8 million. Alta expectsworking interest prior 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.a basket payout. At project payout, Alta will be assigned a 20% reversionary working interest, proportionately reduced to Contango, Alta and the other participants.participant. Alta will receive an overriding royalty interestORRI 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. 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 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

Ameritex has currently identified four prospect areas in which we will participate, all of which are located in south Texas.

In March 2005, we participated with Ameritex in drilling an exploratory 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 also drilled two exploratory wells, the Hargis #1 located in Live Oak County, Texas 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 29.5% share of the dry hole and 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 18.8%. The well has been completed and is 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 October 2004, Coastline purchased 3-D seismic data on an approximate 22 square mile area along with a lease option for an initial 180 day period, providing Coastline the right to purchase leases on 15,060 acres in Jim Hogg County, Texas. The lease option was renewed for an additional 90 days and expired. We agreed to pay 100% of the prospect leasehold costs and carry Coastline on a portion of the drilling costs on the first three wells located within the designated prospect area. In addition, Coastline would receive a 3% overriding royalty interest.

In 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. Our70% share of the lease acquisition costs wasas of August 31, 2006 is approximately $0.4$8.3 million. No drillable prospects were identified

The Arkansas Oil & Gas Commission has now approved thirteen 640-acre drilling units in Conway County, Arkansas that we estimate will allow our partnership to drill and operate approximately 117 horizontal wells. The horizontal wells are estimated to cost between $2.8 to $2.2 million each. We estimate our working interest and net revenue interest in these Alta operated wells will average approximately 45% and 35%, respectively. Alta intends to continue to seek approval from the Arkansas Oil & Gas Commission for additional 640-acre units.

In March 2006, we spud the first of the 21 wells currently planned to be operated by Alta during our fiscal-year ending June 30, 2007, the Alta-Beck #1-32H (the “Alta-Beck”) with a 38.65% working interest. We expect to complete the Alta-Beck and have pipeline hookup in February 2007. In June 2006, we spud the Alta-Briggler #1-31H, with a 69.74% working interest. We finished drilling in July 2005,2006 and expect to begin producing in February 2007. In July 2006, we electedmoved the rig onto the Alta-Thines #1-30H, with a 34.87% working interest.

Index to allow bothFinancial Statements

We completed drilling this well in August 2006, and anticipate completion and pipeline hookup in February 2007. The 8/8ths cost for drilling these three wells as of August 31, 2006 was $5.6 million ($2.5 million net to Contango). We encountered significant time and cost overruns over our lease options to expire.pre-drill Authorization for Expenditure (“AFE”) estimates in all three wells. We have since declined to invest in any further prospects related toestimate an additional 8/8ths cost of $3.8 million will be required for frac, completion and hook-up of the above acreage and have expensedthree wells. Our share of these costs will be $1.9 million. For the remaining capital investment18 wells, our estimated costs in the 12 wells for which we have received an AFE as of approximately $1.2 million asAugust 31, 2006 is $11.2 million. Alta has executed a drilling contract with a second contract drilling company and we anticipate we will have two rigs running beginning in September 2006. We currently anticipate and are budgeting for Alta to operate both rigs throughout our fiscal year-end of June 30, 2005.

2007. Our plans and budgets, however, are subject to anticipated drilling improvements and cost efficiencies as we develop a learning curve from drilling multiple wells.

In May 2005,addition, we drilled a shallow exploratory wellhave been integrated into 54 wells located in Jim Hogg County which provedour Arkansas Fayetteville Shale play as of August 31, 2006, that are being operated by a third party independent oil and gas exploration company (“Integrated Wells”). Of these, three are vertical natural gas wells that are currently producing. Thirteen more are producing horizontal wells. Of the 16 producing wells, the 8/8ths production from 13 wells is over 15 million cubic feet per day (“MMcf/d”) as of August 31, 2006. Production data from the remaining three wells is not yet available. The remaining 38 horizontal wells are either currently being drilled or are expected to be unsuccessful. Our 100%drilled over the next three months with our net share of dry holethe total drilling costs for this shallow well was approximately $0.2estimated at $5.8 million.

Our average working and net revenue interest in these 54 Integrated Wells thus far is 7.28% and 5.78%, respectively.

Sale of South Texas PropertiesOther Drilling Activities

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 byAs a majorityresult of the Company’s stockholders at a Special Meetingintent to focus on developing our Arkansas Fayetteville Shale play and our offshore Gulf of Stockholders on December 29, 2004. Approximately 16 BcfeMexico prospects, we have discontinued our south Texas drilling program with Ameritex Minerals and Exploration, Ltd. and Coastline Exploration, Inc. We do anticipate, however, drilling three onshore wells in each of proven reserves were sold having a pre-tax net present value using a 10% discount rate as ofLouisiana, Texas and Alabama with Alta prior to our fiscal year-end 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 29, 2005. The Company recognized a gain on sale of approximately $16.3 million for the year ended June 30, 2005.

2007.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. As of June 30, 2005,2006, Contango and its affiliates had interests in 5063 offshore leases. AsOn August 16, 2006, REX was the apparent high bidder on three lease blocks at the Central Gulf of September 7, 2005, Contango and its affiliatesMexico Lease Sale #200. To date, none of the lease blocks have interestsbeen awarded. The outcome of the August 16 lease sale is being challenged in 52the U.S. District Court in New Orleans by the State of Louisiana. The sale covered areas in the western part of the Outer Continental Shelf, offshore leases.from the Texas coastline. See “Offshore Properties” below for additional information on our offshore properties.

As of June 30, 20052006, Contango owned a 33.3%42.7% equity interest in REX, a 66.7%76.0% equity interest in COE, and a 50.0% equity interest in Magnolia Offshore Exploration LLC (“MOE”),MOE, all of which were formed for the purpose of generating exploration opportunities in the Gulf of Mexico. These companies have collectively licensed approximately 3,8003,900 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 REX, COE and COE.MOE.

Republic Exploration LLC.On September 2, 2005, Contango purchased an additional 9.4% ownership interest in REX for $5.625 million from JEX. As a result of this purchase, our equity ownership interest in REX increased from 33.3% to 42.7%. As of June 30, 2005,2006, Contango had approximately $5.7$5.8 million invested in REX for a 33.3% ownership interest.REX. The three other members of REX are JEX, its managing member, a privately held investment company, and a privately held seismic company. Both have comprehensive offshore experience. REX holds a non-exclusive license to approximately 2,0302,083 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 REX are subject to a 3.3% overriding royalty interestORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for more information on REX’s offshore properties. In addition, please see “Subsequent Events” on page F-25 for

Index to Financial Statements

West Delta 43 (“Skip Jack”), a discussion of our recent purchase of additional interestsREX prospect was spud in REX.

June 2006 and determined to be a dry hole. Our dry hole costs were approximately $3.2 million.

Contango Offshore Exploration LLC.On September 2, 2005, Contango purchased an additional 9.4% ownership interest in COE for $1.875 million from JEX. As a result of this purchase, our equity ownership interest in COE increased from 66.6% to 76.0%. As of June 30, 2005,2006, Contango had approximately $13.7$15.0 million invested in COE, for a 66.7% ownership interest. JEX is the only other member and acts as the managing member.which COE had invested approximately $13.7 millionhas used to acquire and reprocess 1,7751,815 blocks of 3-D seismic data and to acquire leases in the Gulf of Mexico. The two other members of COE are JEX, its managing member, and a privately held investment company. All leases are subject to a 3.3% overriding royalty interestORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for additional information on COE’s offshore properties.

Grand Isle 72 (“Liberty”), a COE prospect, was successfully tested in March 2006. We believe, subject to Gulf of Mexico weather conditions, that this well will be on-stream by November 2006, with an estimated initial 8/8ths equivalent production rate of 7-10 million cubic feet equivalent per day (“MMcfe/d”). COE has a 50% working interest and a 40% net revenue interest in this well, while COI has a 25% working interest and a 20% net revenue interest. Our third party partners have a 25% working interest and a 20% net revenue interest in the well.

During the year, COE borrowed $250,000 from the Company under a promissory note (the “Note”) to fund a portion of its share of development costs at Grand Isle 72. In addition, please see “Subsequent Events” on page F-25 forJuly 2006, COE borrowed an additional $500,000 under the same Note. The Note bears interest at a discussionper annum rate of our recent purchase of10% and is payable upon demand. We anticipate that COE will need to borrow an additional interests$1.5 million from the Company to complete pipeline hook-up and begin production.

Grand Isle 70, a COE prospect, was spud in COE.

July 2006 and proved to be a discovery. The well has been temporarily abandoned while alternative development scenarios are being evaluated. COE has a 52.6% working interest and a 42.1% net revenue interest in this well. Our third party partners have a 43.75% working interest and a 37.9% net revenue interest, and COI has a 3.65% working interest and a 0% net revenue interest.

Magnolia Offshore Exploration LLC. As of June 30, 2005,2006, Contango had approximately $0.9$1.0 million invested in MOE. Contango purchased a 50% working interest in MOE in October 2001. JEX is the only other member of Magnolia Offshore ExplorationMOE and acts as the managing member, deciding which prospects Magnolia Offshore ExplorationMOE may acquire, develop, and exploit. MOE ownsMOE’s license rights to 3-D seismic data covering 600 blockshave been assigned to COE. All leases are subject to a 3.3% ORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for additional information on MOE’s offshore properties.

Current Activities.In August 2005, Hurricane Katrina struck the Gulf of Mexico continental shelf.

Current Activities.Asand the Gulf Coast of June 30,the United States, and in September 2005, ourHurricane Rita struck the same region. At the time, the Company did not operate or own any production platforms or pipeline facilities in the Gulf of Mexico. However, the Company did have a non-operating working interest or ORRI in three offshore blocks: Ship Shoal 358, Eugene Island 113-B and Eugene Island 76 and depends on third-party operators for the operation and maintenance of these production platforms. In the aftermath of the hurricanes, the Ship Shoal 358 and the Eugene Island 113-B platforms sustained damage and have now been repaired. Eugene Island-113B resumed production in April 2006, and at August 31, 2006 was producing at a rate of 7.7 MMcfe/d, while the Ship Shoal 358 A-3 well resumed production in April 2006 and on August 28, 2006 was producing at a rate of approximately 2.5 MMcfe/d. Contango’s net revenue interest in these wells is 3.1% and 5.8%, respectively. The Company was not responsible for any of the capital costs required to repair the damaged platforms, pipelines, or other damaged facilities related to these wells. The Company was not materially impacted by the temporary loss of production from these two wells. Eugene Island 76, a REX prospect, was successfully tested in 2005 and productionbegan producing in January 2006. The well is expected to begin by the end of fall 2005.currently producing at approximately 7.5 MMcfe/d. Contango’s net revenue interest is 2.14%. REX was carried in the well and owns an overriding royalty interestORRI of 5% until payout, after which REX will receivehas the option to elect an 8.33% overriding royalty interest with an option to electORRI or a 25% working interest uponafter payout.

Index to Financial Statements

We are currently drilling our Eugene Island 10 (“Dutch”) prospect in the Gulf of Mexico, which is operated by COI. Our capital expenditure budget calls for us to invest approximately $3.7 million in estimated dry hole costs in the drilling of Eugene Island 10. In the event we have exploration success, our capital budget will be significantly increased as we will incur additional costs to complete the well and pay for production facilities. In the event Eugene Island 10 is determined to be a dry hole, we will incur a $5.4 million dry hole cost charge and an impairment charge of approximately $2.0 million. In the event of tropical storms or hurricanes in the Gulf of Mexico while Eugene Island 10 is drilling, our estimated dry hole costs could be significantly greater.

In March 2005,2006, REX and COE were high bidders on threewas awarded the following six lease blocks that were offered atfrom the Central Gulf of Mexico Lease Sale #194.#198 for an aggregate purchase price of approximately $0.9 million: South Marsh Island 57, South Marsh Island 59, South Marsh Island 75, South Marsh Island 282, Ship Shoal 14 and Ship Shoal 25. The blocks are complimentary to our existing Ship Shoal and South Marsh Island prospects. In June 2006, REX acquiredwas awarded the Vermillion 194 and West Cameron 107 offshore GulfDelta 77 lease blocks for an aggregate purchase price of Mexico lease block for approximately $0.3 million and COE acquired the Viosca Knoll 475 offshore Gulf of Mexico lease block for approximately $0.3 million and REX and COE each acquired a 50% working interest in the Eugene Island 168 lease block.

$1.8 million.

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,April 2006, COE was awarded the apparent high bidder onfollowing two lease blocks offered atfrom the WesternCentral Gulf of Mexico Lease Sale #196,#198 for an aggregate purchase price of approximately $1.4 million: Grand Isle Block 70 and Ship Shoal Block 263. In May 2006, COE was awarded the East Breaks 366Viosca Knoll 119 and the East Breaks 410 blocks. The bid383 lease blocks for an aggregate purchase price for the two blocks wasof approximately $0.6$0.4 million. The blocks are complementary to our East Breaks 369 and 370 prospects and are located in approximately 2,000 feet of water.

REX and COE have farmed out the following five lease blocks: Main Pass 221, East Breaks 369/370, and Vermillion 154, and the West Cameron 133.154. Main Pass 221 is expectedwas drilled and was determined to be drilled 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.

dry hole. East Breaks 369 is expected to spud prior to the end of the first calendar quarter 2006 and East Breaks 370 isare expected to spud prior to Septemberin 2007. COE will receive a 4.27% overriding royalty interest4.3% ORRI before project payout and a 7.2% overriding royalty interestORRI after project 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 133, 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 expects an exploratory well to be drilled in the spring of 2006. The Vermillion 154 prospect has been farmed out, and REXthe operator expects theto drill an exploratory well prior to be drilled in July 2008.

During the fiscal year, two lease blocks, Viosca Knoll 116 and 119, were relinquished to the Minerals Management Service (“MMS”). West Delta 36 was farmed out during the last quarter and has been completed as a discovery. REX holds a 3.67% ORRI with an option at payout to increase the ORRI to 5% or convert the ORRI to a 25% working interest.

Record title interest in the Vermilion 73 and South Marsh Island 247 leases has been assignedfarmed out to a common third party. The South Marsh Island 247 prospect is in the process of being farmed out, and if successful, aA timetable for drilling the prospect will then betwo prospects has not yet been established. Under the farm-out agreement, REX reserves a 5% overriding royalty interestORRI before payout in both prospects. In the Vermilion 73 prospect, REX also has the option after payout to maintain its 5% overriding royalty interestORRI or acquire a 25% working interest in the prospect.

We recently drilled on our West Cameron 174 prospect. The well is in the process of being plugged and abandoned. Our 10% working interest share of the dry hole costs for the 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 to evaluate alternative plans that will support potential future drilling of the prospect.

The Minerals Management Service (“MMS”)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 billion 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 an interval between 18,000 to less than 20,000 feet. Royalty relief is available on the first 35 Bcf of natural gas production if produced from well depths at or greater than 18,00020,000 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.

Index to Financial Statements

Contango Operators, Inc.

Contango Operators, Inc. (“COI”)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,COI may also operate and as part of our business strategy, COI will act as the operator on certainacquire significant working interests in offshore prospects.exploration and development opportunities under farm-in agreements with third parties.

Current Activities.COI plansThe Company had an offshore exploration discovery at its Grand Isle 72 (“Liberty”) prospect in March 2006. As of August 31, 2006, the Company has invested approximately $8.6 million to drill and operate two prospects in which our anticipated dry hole working interest commitmentscomplete this well. We estimate an additional $1.8 million will be approximately $5 million per well. Inrequired to build production and pipeline facilities to commence production. We believe the first exploratory well thewill be on-stream by November 2006, with an estimated initial 8/8ths equivalent production rate of 7-10 MMcfe/d. The net revenue interests to COI and COE after well completion is estimated to be 20% and 40%, respectively.

COI began drilling its Eugene Island 10 (“Dutch”) prospect in July 2006. COI will pay a 35% working interest before casing point electionthrough completion of the well and will have apay an 18.3% working interest after a casing point election has been made.thereafter. After a back-in by the farmorfarmors of the block, this working interest iswill be reduced to 13.75%. Our partially owned subsidiary, REX will pay on a 15% working interest before casing point electionthrough completion and will have a 48.75%65% working interest after a casing point election has been made andthereafter, reduced to 48.75% after the farmor’sfarmors’ back-in. AsCOI’s share of September 7, 2005, COI has securedthe dry hole costs is estimated to be $3.7 million. The prospect is being drilled under a drilling rig, consummated afixed 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. Netcontract. The net revenue interestinterests to COI and REX, after casing point electionshould the well be successful, and after the farmor’sfarmors’ back-in working interest, is estimated to be 11% and 39%, respectively.

In the second exploratory well, located inevent Dutch is successful, 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 andCompany will have the opportunity to drill additional wells but may be required to pay higher costs for rigs and related marine services as a 50% working interest after a casing point election has been made. Asresult of September 7, 2005, the demand for such equipment related to generally strong commodity prices and the demand for offshore services.

COI has identified and reserved a drilling rig and is in the process of negotiating a turn-key drilling contract. COI expects to beginbegan drilling the initial exploratory well by calendar year-end 2005. COI’s estimated share of drilling costs is $5 million. Net revenue interest to COIHigh Island A279 (“Juice”) in June 2006, and COE after casing point election and after COE’s back-in working interest is estimateddetermined it 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.

a dry hole. Our dry hole costs were approximately $2.7 million.

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:August 31, 2006:

Index to Financial Statements

Farmed-Out Properties. The following table sets forth the working interests and net revenue interests owned by Contango and related entities in the Gulf of Mexico which have been farmed out as of September 7, 2005:August 31, 2006:

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

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 LLC:
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

Farmed-In Properties. The following table sets forth the working interests and net revenue interests owned by Contango and related entities in the Gulf of Mexico which have been farmed in as of August 31, 2006:

Index to Financial Statements

Leases.The following table sets forth the working interests owned by Contango and related entities in the Gulf of Mexico as of August 31, 2006:

Index to Financial Statements

Freeport LNG Development, L.P.

As of June 30, 2005,2006, the Company has invested $3.0$3.2 million and owns a 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG”), a limited partnership formed to develop, construct and operate a 1.5 billion cubic feet per day (“Bcf/d”) liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas.

In July 2004, Freeport LNG finalized its transaction with ConocoPhillips for the financing, construction and use of the LNG receiving terminal in Freeport, Texas. ConocoPhillips executed a terminal use agreement for 11.0 Bcf/d of regasification capacity, purchased a 50% interest in the general partner managing the Freeport LNG project and agreed to provide construction funding to the venture. This construction funding will beis non-recourse to Contango. The Dow Chemical Company (“Dow Chemical”) has also executed a terminal use agreement for regasification capacity of 500 million cubic feet per day (“MMcf/d”)d and, in an unrelated transaction with another limited partner, has purchased a 15% limited partnership interest in Freeport LNG. Freeport LNG is responsible for the commercial activities of the partnership, while ConocoPhillips, under a construction advisory and management agreement, is managing the construction of the facility.

In 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

Index to Financial Statements

facility commenced on January 17, 2005. The terminal’s Phase I capacity has been sold to ConocoPhillips (1.0 Bcf/d) and Dow Chemical (0.5 Bcf/d) and construction is expected to be completed by January 2008. 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 befor Phase I is being provided by ConocoPhillips through a construction funding by ConocoPhillips. Construction has startedloan, with a budget, including a significant amount of contingency, of approximately $780 million. ConocoPhillips has 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. Debtdebt service for Tranche A isbeing provided by the terminal use agreement with ConocoPhillips. ConocoPhillipsAdditional financing has also agreed to loan the project the remaining 50% of construction funding above $460been obtained through a $383.0 million (“Tranche B”). In addition to the $160 million for Tranche B,private placement note issuance by Freeport LNG has committedwhich closed on December 19, 2005. The funds from the notes are being used to $43 millionfund the balance of work that is not covered by the ConocoPhillips agreements and is therefore a sole obligationPhase I construction of Freeport LNG. Freeport LNG is actively workingLNG’s liquefied natural gas regasification terminal. The funds will also be used 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-fundingdevelopment of somean integrated natural gas storage salt cavern and a portion of the cost of an expansion assets (discussed below)of the LNG terminal (“Phase II”). Such third-party debt will beThe notes are secured primarily by payments obligated under the terminal use agreement with Dow Chemical. We do

Phase II expansion of the LNG terminal may include a second LNG unloading dock, additional send-out and additional storage capacity. Expansion applications have been submitted to the FERC and other governmental agencies and assuming approval of these applications in late 2006, Phase II capacity could be available in late 2009. Part of the Phase II capacity has been sold to MC Global Gas Corporation, a wholly-owned subsidiary of Mitsubishi Corporation and to ConocoPhillips under long-term contracts. Expansions of the terminal included in the current applications are planned and will be constructed as additional capacity is sold.

Although we anticipate that we may, from time-to-time, be required to provide funds to the Freeport LNG project, and intend to provide our pro rata 10% of any required equity participation. Currently, if no third-party financing is obtained by Freeport LNG, our 10% share ofparticipation, we believe the project costs not financed under the ConocoPhillips agreement is approximately $4.3 million. Further, once third-party debt is drawn, the Tranche B loanwill continue through Phase I construction and Phase II pre-development with no further significant funds likely being required from ConocoPhillips will no longer be available to Freeport LNG.Contango.

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

InAs of June 2004, our wholly-owned subsidiary,30, 2006, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, held a direct investment in the three alternative energy companies described below. Our investment in these companies is less than 20% and we account for these investments under the cost method.

Trulite, Inc.As of June 30, 2006, CVCC had invested $0.9 million in Trulite, Inc. (“Trulite”) in exchange for 2,001,014 shares of Trulite common stock, which represents an approximate 17% ownership interest. Trulite develops lightweight hydrogen generators for fuel cell systems. In August 2006, the Company loaned $125,000 to Trulite under a promissory note (the “Trulite Note”). The Trulite Note bears interest at a per annum rate of 11.25% until February 9, 2007, at which point the per annum rate will change to prime rate plus three percentage points. All principal and accrued and unpaid interest on the Trulite Note is due on May 1, 2007.

Moblize Inc.As of June 30, 2006, CVCC had invested $0.6 million in Moblize Inc. (“Moblize”) in exchange for 324,324 shares of Moblize convertible preferred stock, which represents an approximate 19% ownership interest. Moblize develops real time diagnostics and field optimization solutions for the oil and gas industry using open-standards based technologies. Moblize is currently deploying its technology in oil fields near Houston belonging to Chevron U.S.A. Inc. and on our Grand Isle 72 development, which will allow COI to remotely monitor, control and record, in real time, daily production volumes.

In August 2006, the Company exercised its right pursuant to two warrants, to purchase an additional 324,324 shares of Moblize convertible preferred stock for $0.6 million. This brings the Company’s total investment in Moblize to $1.2 million, with approximately a 33% ownership interest.

Gridpoint, Inc. In May 2006, CVCC invested $1.0 million in Gridpoint, Inc. (“Gridpoint”) in exchange for 333,333 shares of Gridpoint preferred stock, which represents an approximate 3% ownership interest.

Index to Financial Statements

Gridpoint’s intelligent energy management (IEM) products ensure clean, reliable power, increase energy efficiency, and integrate renewable energy. With GridPoint, residential and business owners can protect themselves from power outages, manage their energy online and reduce their carbon footprint. GridPoint’s “plug-and-play” appliances are easy to install and are sold through a network of premium home builders, utilities, retail chains and government entities as well as installers and contractors of electrical, heating, air-conditioning, home automation, power quality and renewable energy systems.

In June 2004, CVCC acquired a 32% membership interest in Contango Capital Partnership Management, LLC (“CCPM”). for $0.5 million. 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 technologiesmarket. CVCC is the 25% limited partner of, and to expose us to leading edge technologies and opportunities in alternative energy markets. Our initial cash contributionCCPM is the general partner of, $0.5 million was used to fund the initial overhead for the sourcing and management of energy venture capital investments to be evaluated and made by CCPM. We hold two of seven seats on the board of directors of CCPM.

In July 2004, CVCC committed $0.1 million in exchange for a limited partnership interest in Trulite Energy Partners, L.P. Trulite Energy Partners, L.P. was an investor and principal shareholder of Trulite Inc. Trulite, Inc. develops lightweight hydrogen generators for fuel cell 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., which was formed in January 2005 for the purpose of investing in the energy venture capital market andmarket. Contango Capital Partners, L.P. then 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 investmentinvestments with a total capitalization of $8.2 million in the form of contributed stock, cash, and future cash commitments. CCPM is the general partnerPrior to CVCC holding a direct interest in Trulite and manager of the Fund.

As of June 30, 2005,Moblize, the Fund owned equity interestspreviously held these investments. The Fund also had an investment in four portfolio alternative energy companies, including Trulite, 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”). Synexus Energy Inc. is 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.

During the year ended June 30, 2006, the Fund invested an additional $0.8 million in Trulite, $0.6 million in Moblize, and an additional $1.0 million in Synexus. In April 2006, Trulite acquired Synexus’ technology. In May 2006, the Fund distributed its pro rata shares of Trulite to CVCC. In June 2006, the Fund sold its investment in Moblize to CVCC for $0.6 million.

As of June 30, 2006, CVCC owns 25% of the Fund. The Fund currently holds a direct investment in the two alternative energy companies described below. We account for these investments under the equity method. CCPM is the general partner of the Fund.

Protonex Technology Corp.Corporation.As of June 30, 2006, the Fund has invested $1.5 million in Protonex Technology Corporation (“Protonex”) in exchange for 2,400,000 shares of Protonex stock, which represents an approximate 7% ownership interest. Protonex 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. During the period, Protonex began trading its common shares on the AIM market of the London Stock Exchange under the symbol “PTX.L”. As a result, the Fund marks-to-market its investment in Protonex based on public pricing. At June 30, 2006, the Fund’s investment in Protonex had a mark-to-market value of approximately $3.8 million.

Jadoo Power Systems.The Fund has invested approximately $1.2 million and owns 2,200,000 shares of Jadoo Power Systems (“Jadoo”) stock, which represents an approximate 5% ownership interest. Jadoo develops high energy density power products for the law enforcement, military and electronic news gathering applications.

CVCC’s 25% limited partnership interest in the 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 its $1.5 million commitment to2006, the Fund, bringing its total cashFund’s investment in alternative energy toJadoo had a valuation of approximately $1.5$1.2 million.

As of June 30, 2005,Since the Fund’s inception, the Company has recorded an approximate $0.75a cumulative $0.8 million increase to our investment resulting primarily from unrealized gains of the Fund as a result of a mark-to-market adjustmentadjustments that washave been made due to the increase in the value of our alternative energy investments, bringing our total investment in alternative energy investments, including cumulative mark-to-market adjustments, as of June 30, 2006, to approximately $2.3 million.$4.5 million, consisting of $3.7 million of cash invested and $0.8 million of aggregate fund mark-to-market increases, net of equity earnings and losses.

Index to Financial Statements

Marketing and Pricing

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

gas and oil. The Company has outsourced the marketing of its offshore natural gas and oil production volume to a privately-held third party marketing firm.

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:

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.

GovernmentGovernmental 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 barrels 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”) 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”) 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 U.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

Index to Financial Statements

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, 2006,2007, 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 beis required to obtain surety bonds of $200,000 per lease for exploration and $500,000 per lease for developmental activities.

Index to Financial Statements

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 relating to:

Freeport LNG received this authorizationThe FERC approved the project in June 2004 to site, construct and operate our proposed LNG receiving terminal. In2004. On 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 to 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. In some cases, these laws and regulations could require Freeport LNG to obtain governmental authorizations before conducting 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

Index to Financial Statements

pollution. As with the industry generally, compliance with these laws increases the overall cost of business. Environmental 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 to 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 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 six 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 for 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.

services and an independent third party engineering firm to calculate our reserves.

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. Mr. Peak entered the energy industry in 1972 as a commercial banker and held a variety of financial and executive positions in the oil and gas 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 in 1967, and an MBA from Columbia University.University in 1972. 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.

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.

Sergio Castro.Mr. Castro joined Contango in March 2006 as Treasurer and was appointed Vice President and Treasurer in April 2006. Prior to joining Contango, Mr. Castro spent two years as a Litigation Consultant for UHY Advisors TX, LP. From 2001 to 2004, Mr. Castro was a lead credit analyst for Dynegy Inc. From 1997 to 2001, Mr. Castro worked as an auditor for Arthur Andersen LLP, where he specialized in energy companies. Mr. Castro was honorably discharged from the U.S. Navy in 1993 as an E-6, where he served onboard a nuclear powered submarine. Mr. Castro received a BBA in Accounting in 1997 from the University of Houston, graduating summa cum laude. Mr. Castro is a Certified Public Accountant and a Certified Fraud Examiner.

Index to Financial Statements

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 asin a senior operations manager forexecutive position with USENCO International, Inc. and related companies in China and Ukraine 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. Mr. Brehmer holds a BBA from Drake University in Des Moines, Iowa.

Joseph S. CompofeliceCharles M. Reimer.. Mr. Compofelice has beenReimer was elected as a director of Contango since 2002.in 2005. Mr. CompofeliceReimer is Managing DirectorPresident of Catalina Capital Advisors LP, a boutique financial advisory, mergerFreeport LNG Development, L.P, and acquisition investment bank. He ishas experience in exploration, production, liquefied natural gas (“LNG”) and business development ventures, both domestically and abroad. From 1986 until 1998, Mr. Reimer served as the Chairmansenior executive responsible for the VICO joint venture that operated in Indonesia, and provided LNG technical support to P. T. Badak. Additionally, during these years he served, along with Pertamina executives, on the board of directors of the BoardP.T. Badak LNG plant in Bontang, Indonesia. Mr. Reimer began his career with Exxon Company USA in 1967 and held various professional and management positions in Texas and Louisiana. Mr. Reimer was named President of Trico Marine Services, Inc., a providerPhoenix Resources Company in 1985 and relocated to Cairo, Egypt, to begin eight years of marine support vessels serving the international natural gasassignments in both Egypt and oil industry,Indonesia. Prior to joining Freeport LNG Development, L.P. in December 2002, Mr. Reimer was President 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.Cheniere Energy, Inc.

Steven L. Schoonover.Mr. Schoonover was elected as a director of Contango in 2005. Mr. Schoonover currently serves as Chief Executive Officer of Cellxion, L.L.C., a providercompany specializing in construction and installation of servicestelecommunication buildings and equipmenttowers, as well as the installation of high-tech telecommunication equipment. From 1990 until its sale in November 1997 to the power generation and heavy processing industries. For the period 1998 through 2002,Telephone Data Systems, Inc., Mr. Compofelice was Chairman and CEOSchoonover served as President of CompX InternationalBlue Ridge Cellular, Inc., a producerfull-service cellular telephone company he co-founded. From 1983 to 1996, he served in various positions, including President and Chief Executive Officer, with Fibrebond Corporation, a construction firm involved in cellular telecommunications buildings, site development and tower construction. Mr. Schoonover has been awarded, on two occasions with two different companies, Entrepreneur of hardware for the office furniture industry. From 1994 through 1997, Mr. Compofelice was a DirectorYear, sponsored by Ernst & Young, Inc Magazine 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.USA Today.

Darrell W. Williams. Mr. Williams has been a director of Contango since 1999. Mr. Williams is President and CEO of Porta-Kamp International LP, which specializes in the manufacture, supply and construction of remote area housing, and CEO of Clearwater Environmental Systems, a manufacturer of sewage and water treatment systems. From 2002 until 2005, Mr. Williams was Managing Director of Catalina Capital Advisors, LP, a boutique financial advisory, merger and 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.LP. Prior to joining Deutag,Catalina, Mr. Williams was in senior executive positions with Deutug Drilling, GmbH (1993-2002), 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.

Index to Financial Statements

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, 2005,2006, each outside director received a quarterly retainer of $5,000 and a quarterly stock option grant to purchase 3,000 shares of common stock. 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.

We expect to exercise our option to extend our lease term for five years, beginning on November 1, 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.com.www.contango.com.

Available Information

In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating the Company. An investment in the Company is subject to risks inherent in our business. The trading price of the shares of the 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 the Company may decrease, resulting in a loss. The risk factors listed below are not all inclusive.

We have outsourced the marketing of our production and 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 couldwould 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.

Index to Financial Statements

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 limits 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 ofrecent addition to our business strategy. COI has submitted a plan of exploration withis currently the Minerals Management Service (“MMS”) as the designated operator for both the Grand Isle 72 andour exploration prospect at 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.10. Although as a company we have previously taken working interests in offshore prospects, our recent exploration prospects are the first wells in which we have previously never assumed the role of operator.

Estimated drilling costs could be significantly higher if we encounter difficulty in drilling offshore exploration wells.

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.

We may have excessive resources committed to our Arkansas Fayetteville Shale Play.

During fiscal year 2006, we invested $7.7 million in our Arkansas Fayetteville Shale play. Our capital budget for our fiscal year ending June 30, 2007 calls for us to invest over $40 million in the Arkansas Fayetteville Shale. This represents approximately 75% of our exploration and development budget, and approximately 70% of our total CAPEX budget. We intend to borrow significant capital against anticipated revenues and production, and should the wells not perform as expected, we will likely encounter difficulty repaying this debt. There can be no assurance that our drilling activity in this area will produce economically feasible wells. It is early in the process and we are still learning how to drill, complete, frac and produce these wells. Additionally, all of our wells are operated by outside companies. As a result, we have a limited ability to exercise influence over operations or their associated costs and risks.

Increasing capital investment in certain prospects increases our dry hole risk exposure.

Beginning in the spring of 2005, we decided to increase our capital investment in certain exploration

Index to Financial Statements

prospects, including our onshore Arkansas Fayetteville Shale prospect and our offshore Gulf of Mexico prospects. From July 1, 2005 through August 31, 2006, we have invested, or committed to invest, approximately $24.4 million in our offshore prospects, and $17.8 million in the Arkansas Fayetteville Shale. 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 $1.0 million.

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 the Freeport LNG receiving facility that is being constructed in Freeport, Texas. The LNG project received 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 is 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, including any expansion of the facility, we may lose our 10% investment in the project.

In December 2003, ConocoPhillips andA majority of the Freeport LNG signed anfinancing is being provided by ConocoPhillips through a $620.0 million construction loan, with debt service being provided by the terminal use agreement providing for ConocoPhillips’ participationwith ConocoPhillips. Additional financing has been obtained through a $383.0 million private placement note issuance by Freeport LNG which closed on December 19, 2005. The notes are secured primarily by payments obligated under the terminal use agreement with Dow Chemical. Upon any significant increase in Freeport LNG’s projectconstruction costs to buildcomplete construction of the receiving terminal. ConocoPhillips will acquire 1 Bcf/d of capacity in the terminal for its use. ConocoPhillips purchasedfacility or upon a 50% interest in the general partner of Freeport LNG and, as noted above, has agreedcall to provide substantially allfund construction of the construction funding. Without such financing or upon any significant shortfall in project funding,proposed expansion, we may not have the financial resources to fund our 10% ownership share of construction costs. If we are unable to fund 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.project or be forced to sell our interest in an untimely fashion or on less than favorable terms.

If we default on our Sundance loan we could lose our 10% investment in the LNG receiving facility in Freeport, Texas.

Our three-year $20.0 million term loan agreement dated April 27, 2006 with The Royal Bank of Scotland plc is secured with the stock of Contango Sundance, Inc. (“Sundance”), our wholly-owned subsidiary. Sundance owns a 10% limited partnership interest in Freeport LNG Development, LP, which owns the Freeport LNG facility. If an event of default occurs under the term loan agreement, we could lose our investment in the Freeport LNG facility.

Index to Financial Statements

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 allthe majority 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 reserves.

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, 2005.time. 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.

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 us by our independent third party reservoir engineers. If those reports

Index to Financial Statements

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:

Index to Financial Statements

Offshore operations also are subject to a variety of operating risks peculiar to the marine environment, such as capsizing collisions and collisions. In addition, offshore operations, and in some instances, operations along the Gulf Coast, are subject to 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.

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.

All of our natural gas and 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.

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 to not to incur the expense of retaining title 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.

Index to Financial Statements

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. 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 operate.

Other companies currently operate 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:

Index to Financial Statements

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:

Index to Financial Statements

Our common stock is thinly traded.

Contango has approximately 14.715 million shares of common stock outstanding, held by approximately 115124 holders of record. Approximately 2.6Directors and officers own or have voting control over approximately 4 million shares are owned by directors and officers.shares. Since our common stock is thinly 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 InformationItem 1B.Unresolved Staff Comments

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.

None.

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 Mcfthousand cubic feet (“Mcf”) of natural gas.

Index to Financial Statements

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: