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Article by DailyStocks_admin    (08-01-08 05:09 AM)

Contango Oil and Gas Co. CEO KENNETH R PEAK bought 25000 shares on 7-24-2008 at $78.46

BUSINESS OVERVIEW

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 in the Arkansas Fayetteville Shale. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator on certain offshore 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 companies 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 totally upon our alliance partners for prospect generation expertise. Our alliance partners, Juneau Exploration, L.P. (“JEX”) and Alta Resources, LLC (“Alta”) are experienced and have successful track records in exploration.

Using our limited capital availability to increase our reward/risk potential on selective prospects. We have concentrated our risk investment capital in two prospect areas; our onshore Arkansas Fayetteville Shale play and our offshore Gulf of Mexico prospects. Exploration prospects are inherently risky as they require large amounts of capital with no guarantee of success. COI drills and operates our offshore prospects. Should we be successful in any of our offshore prospects, we will have the opportunity to spend significantly more capital to complete development and bring the discovery to producing status.

Operating in the Gulf of Mexico. COI was formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. Assuming the role of an operator represents a significant increase in the risk profile of the Company since the Company has limited operating experience. While COI has historically drilled turnkey wells, adverse weather conditions as well as difficulties encountered while drilling our offshore wells could cause our contracts to come off turnkey and thus lead to significantly higher drilling costs.

Arkansas Fayetteville Shale. We have made a major commitment to our Arkansas Fayetteville Shale program and this commitment is expected to continue to grow as we participate in the drilling of hundreds of gross exploration/development wells over the 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 expect to continue to sell some or a substantial portion of our proved reserves and assets to capture current value, using the sales proceeds to further our exploration, LNG and alternative energy investment activities. Since its inception, the Company has sold over $87.0 million worth of natural gas and oil properties, and views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, and as a source of funds for potentially higher rate of return natural gas and oil exploration opportunities.

Controlling general and administrative and geological and geophysical costs . Our goal is to be among the 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, we plan to continue outsourcing our geological, geophysical, and reservoir engineering and land functions, and partnering with cost efficient operators. We have six employees.

Structuring transactions to share risk . Our alliance partners share in the upfront costs and the risk of our exploration 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 or have voting control over approximately 24% of our common stock.

Exploration Alliances with JEX and Alta

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 on the Gulf of Mexico, and generates offshore exploration prospects via our affiliated companies, Republic 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 generally provides for us to pay our share of seismic and lease costs, with Alta generally receiving a negotiated overriding royalty interest (“ORRI”) and a carried or back-in working interest.

Onshore Exploration and Properties

Alta Activities

Arkansas Fayetteville Shale

In March 2005, Contango, Alta and another private company entered into an 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. As of August 31, 2007, we and our partners have acquired or received commitments on approximately 45,300 net mineral acres at a cost of approximately $13.6 million. Contango has a 70% working interest prior to payout. At project payout, Alta will be assigned a 20% reversionary working interest, proportionately reduced to Contango, Alta and the other participant. Alta will receive an ORRI in each lease assignment contingent on the amount of lease burden assigned to the third party royalty owners. Our 70% share of the lease acquisition costs as of August 31, 2007, is approximately $9.5 million.

The Arkansas Oil & Gas Commission has now approved 16 separate 640-acre drilling units in Arkansas that we estimate will allow our partnership to drill and operate approximately 144 horizontal wells. The horizontal wells are estimated to cost between $3.5 to $2.5 million each. Thus far, our working interest and net revenue interest in these Alta operated wells has averaged approximately 46% and 36%, respectively. Alta intends to continue to seek approval from the Arkansas Oil & Gas Commission for additional 640-acre drilling units.

The first wells drilled by Tepee Petroleum as contract operator took considerably longer than expected to drill and incurred significant cost overruns. Of these wells, the Alta-Thines #1-30H is currently producing at 0.5 million cubic feet per day (“Mmcf/d”), the Alta-Ledbetter #1-33H is currently producing at 0.7 Mmcf/d, the Alta-Briggler #1-31H is shut in awaiting pipeline hookup, the Alta-Clark #1-26H is currently producing at 0.7 Mmcf/d and the Alta-Wooten #1-34H is currently producing at 1.0 Mmcf/d. The 8/8ths cost for drilling and completing these five wells is estimated at $20.4 million (approximately $10.6 million net to Contango). We have already invested the $10.6 million as of August 31, 2007 and do not expect to incur any significant additional costs for these five wells. Additionally, two wells, the Alta-Beck #1-32H and the Alta-Kaufman #1-12H have been plugged and abandoned due to mechanical problems at a cost of approximately $4.1 million, net to the Company. This charge was recorded in the fourth quarter of the fiscal year ended June 30, 2007.

Alta Operating Company drilled the next four wells which were all successful. The first of these, the Alta-Huff #1-29H, was spud in March 2007 and is currently producing at 1.6 Mmcf/d. The second well, the Alta- Jones #1-29H, was spud in April 2007 and is currently producing at 3.5 Mmcf/d. The third and fourth wells, the
Alta-Chwalinski #2-29H and Alta-Chwalinski #3-29, were spud in May 2007, simultaneously fraced, and are currently producing at a combined 3.6 million cubic feet equivalent per day (“Mmcfe/d”). These four wells are in and around the Gravel Hill Field area in Van Buren County, Arkansas. In addition, Alta arranged for an independent third party operator to drill two additional wells on Alta’s behalf. The first of these, the Alta-Chwalinski #1-29H, was spud in March 2007 and is currently producing at 1.3 Mmcf/d. The second, the Alta-Koone #1-4H, was spud in March 2007 and is currently producing at 0.4 Mmcf/d. In June 2007, Alta spud the Deltic #1-8H and in August 2007, Alta spud the Alta-Deltic #2-8H which is currently drilling horizontally. We expect to simultaneously frac these two Deltic wells in September 2007. The 8/8ths cost for drilling and completing these eight wells is estimated to be $20.7 million (approximately $10.2 million net to Contango). Of this $10.2 million, we have already expended approximately $8.9 million as of August 31, 2007. Contango’s net average working interest and net revenue interest in the 13 above Alta-operated wells, prior to project payout, are approximately 50% and 40%, respectively. As of August 31, 2007, these Alta-operated wells were producing at a combined rate of 5.2 Mmcf/d, net to Contango.

In addition, we have been integrated by a third party independent oil and gas exploration company into 129 wells as of July 31, 2007 (the “Integrated Wells”). Of these 129 Integrated Wells, 78 are producing. The 8/8ths production rate for 68 of these 78 producing wells was 58 Mmcf/d as of July 31, 2007 (approximately 3.0 Mmcf/d, net to Contango). Production data for the remaining ten producing wells was not available. The remaining 51 Integrated Wells are either currently being drilled or are expected to be drilled over the next several months. The 8/8ths cost for drilling and completing these 129 wells is estimated to be $307.0 million (approximately $17.0 million net to Contango). Of this $17.0 million, we have already invested approximately $12.1 million as of June 30, 2007. Contango’s net average working interest and net revenue interest in these 129 wells are approximately 6% and 5%, respectively.

Texas, Alabama and Louisiana

Outside of Arkansas, we spudded two onshore wells with Alta in fiscal year 2007 and one in fiscal year 2008. The Alta-Ellis #1 in Texas, in which we have a 50% working interest, is currently producing at 0.4 Mmcf/d. We recorded an impairment charge of $0.2 million for this well in December 2006. The Temple Inland #1 in Louisiana, in which we have a 77% working interest, is currently producing at 1.0 Mmcf/d and 30 barrels of oil per day. The Alta-Coley in Alabama, in which we have a 67.5% working interest, was spud in July 2007 and was determined to be a dry hole at a cost of approximately $0.5 million. This charge was recorded in the fourth quarter of the fiscal year ended June 30, 2007.

We have also invested with Alta in the developing West Texas Barnett Shale play in Jeff Davis and Reeves Counties, Texas. Alta has leased approximately 5,800 net mineral acres (4,000 net mineral acres to Contango before a basket payout). A third party operator has drilled several wells near our acreage. Our plans are to monitor activity in this play.

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, 2007, Contango and its affiliates had interests in 70 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.

As of June 30, 2007, Contango owned a 42.7% equity interest in REX, a 76.0% equity interest in COE, and a 50.0% equity interest in MOE, all of which were formed for the purpose of generating exploration opportunities in the Gulf of Mexico. See Exhibit 21.2 for an organizational chart of our subsidiaries. These companies have collectively licensed approximately 4,450 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 MOE.

Republic Exploration LLC. On August 22, 2007, REX was the apparent high bidder on two lease blocks at the Western Gulf of Mexico Lease Sale No. 204. REX bid approximately $1.75 million on High Island 263, and approximately $1.1 million on High Island A38. An apparent high bid (“AHB”) gives the bidding party priority in award of offered tracts, notwithstanding the fact that the Minerals Management Service (“MMS”) may reject all bids for a given tract. The MMS review process can take up to 90 days on some bids. Upon completion of that process, final results for all AHB’s will be known.

In June 2007, REX was awarded State Lease No. 19396 at the State of Louisiana Mineral Lease Sale for an aggregate purchase price of approximately $0.3 million. State Lease No. 19396, together with our other State of Louisiana prospects, are commonly referred to as the “Mary Rose” prospect.

Record title interests in the Vermilion 73 and South Marsh Island 247 leases have been assigned to a common third party. Vermillion 73 was drilled and determined to be a dry hole. REX negotiated with the farmee and lowered its ORRI from 5% to 1.5% on Vermillion 73 in exchange for $35,000 so that another well may be drilled in the same block. The second well at Vermilion 73 was drilled during the second quarter of 2007 and also determined to by dry. South Marsh Island 247 was drilled and determined to be a dry hole. The well was plugged and abandoned on September 3, 2007. REX had reserved a 5.0% ORRI before payout on South Marsh Island 247.

REX and COE have farmed out East Breaks 369/370 and Vermillion 154. East Breaks 369 was spud in March 2007 and determined to be a dry hole. The well has been plugged and abandoned. The farmee has until September 1, 2008 to decide if it will drill East Breaks 370. Vermillion 154 has been farmed out, and the operator expects to drill an exploratory well prior to July 2008.

In February 2007, REX was awarded State Lease 19261 and 19266 at the State of Louisiana Mineral Lease Sale for an aggregate purchase price of approximately $4.6 million ($1.8 million net to Contango).

In November 2006, REX acquired 75% of High Island A243 from a private company in exchange for REX paying all future delay rentals. In November 2006, COE acquired 75% of East Breaks 167, High Island A311, East Breaks 166 and High Island A342 from a private company in exchange for COE paying all future delay rentals.

In October 2006, REX was awarded the following three lease blocks from the Western Gulf of Mexico Lease Sale #200 for an aggregate purchase price of approximately $1.0 million: High Island A196, High Island A197 and High Island A198.

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, 2007, Contango had approximately $5.9 million invested in REX. The three other members of REX are JEX, its managing member, a privately held investment company, and a privately held seismic company. REX holds a non-exclusive license to approximately 2,637 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% ORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for more information on REX’s offshore properties.

In April 2005, REX, along with COI, secured from a third party, the right to earn an assignment of operating rights in Eugene Island 10. In September 2005, REX, COI and other third parties entered into a participation agreement whereby COI was named the operator. See “Contango Operators, Inc.” below for additional information on Eugene Island 10.

Contango Offshore Exploration LLC. Grand Isle 72 (“Liberty”), a COE prospect, began producing in March 2007 and as of August 31, 2007 was producing at a rate of approximately 1.5 Mmcfe/d. COE has invested approximately $5.0 million ($3.8 million net to the Company) in drilling, completion, pipeline and production facility costs as of August 31, 2007. COE’s net revenue interest in this well is 40%. As of June 30, 2007, COE had borrowed $4.3 million from the Company under a promissory note (the “Note”) to fund a portion of its share of development costs at Grand Isle 72. The Note bears interest at a per annum rate of 10% and is payable upon demand.

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

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, 2007, Contango had approximately $19.4 million invested in COE, which COE has used to acquire and reprocess 1,815 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% ORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for additional information on COE’s offshore properties.

Magnolia Offshore Exploration LLC . As of June 30, 2007, Contango had approximately $1.0 million invested in MOE. JEX is the only other member of MOE and acts as the managing member, deciding which prospects MOE may acquire, develop, and exploit. MOE’s license rights to 3-D seismic data have 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.

The 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 20,000 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.

Non-Operated Offshore Wells. The Company has non-operating working interests in three offshore blocks: Ship Shoal 358, Eugene Island 113-B and West Delta 36. Contango’s net revenue interest in these three wells is 5.8%, 3.1% and 3.67%, respectively. The Company depends on third-party operators for the operation and maintenance of these production platforms. As of August 31, 2007, Ship Shoal 358 and Eugene Island 113-B were not producing. Ship Shoal 358 is to be re-completed later this year and Eugene Island 113-B is to have compression installed. West Delta 36 was producing at a rate of approximately 11.5 Mmcfe/d. REX has a 3.67% ORRI before payout in West Delta 36, and at its option, may elect either a 5.0% ORRI or 25% working interest (“WI”) after payout. The Company had a non-operating working interest in Eugene Island 76, but this well depleted in November 2006.

Contango Operators, Inc.

COI is a wholly-owned subsidiary of Contango formed for the purpose of drilling exploration and development wells in the Gulf of Mexico. As part of our strategy, COI will operate and acquire significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, usually under a farm-out agreement with either REX or COE. COI expects to take working interests in these prospects under the same arms-length terms offered to industry third party participants. COI also operates and acquires significant working interests in offshore exploration and development opportunities under farm-in agreements with third parties.

Current Activities. During July 2007, the Company began producing from its Dutch #2 well, successfully completed and production tested its Dutch # 3 well, and spudded its Mary Rose #1 well, located on State of Louisiana Lease No. 18640.

As of August 25, 2007, our Dutch #1 and #2 wells were flowing at a combined 8/8ths production rate of approximately 63.2 Mmcfe/d. COI has invested approximately $11.4 million to drill and complete Dutch #1 and #2, including pipeline and production facility costs. During June 2007, one of the farmors of the Eugene Island 10 block backed in for a 12.5% working interest. Therefore, COI now has a 16.04% WI and REX has a 56.88% WI in each of the Dutch wells. For sales of natural gas, the net revenue interests to COI and REX are approximately 14.7% and 52.1%, respectively, with MMS deep gas royalty relief on the first 15 Bcf of gas produced from the entire field. Once the royalty relief has expired for natural gas, and for all sales of oil and condensate, COI and REX have a net revenue interest of 12.07% and 42.79%, respectively. The lease was farmed in on a produce-to-earn basis. The lease has now been assigned, and REX has earned the lease.

The Company’s Dutch #3 well was production tested in July 2007 at a rate of approximately 34 Mmcfe/d. As of August 31, 2007, the Company had invested approximately $3.7 million to drill and complete this well, including pipeline and production facility costs. We estimate an additional $5.6 million will be required to build production and pipeline facilities to commence production. The well will flow into the same platform currently being used by Dutch #1 and #2 and we expect the well will be on-stream by the end of September 2007. COI has a 16.04% WI and REX has a 56.88% WI in Dutch #3. For sales of natural gas, the net revenue interests to COI and REX are approximately 14.7% and 52.1%, respectively, with MMS deep gas royalty relief on the first 15 Bcf of gas produced from the entire field. Once the royalty relief has expired for natural gas, and for all sales of oil and condensate, COI and REX have a net revenue interest of 12.07% and 42.79%, respectively. Once the second farmor backs in after project payout, COI and REX’s working interests will be reduced to 13.75% and 48.75%, respectively.

We are currently drilling our Mary Rose #1 prospect, located off the coast of Louisiana, which is operated by COI. Our capital expenditure budget calls for us to invest approximately $2.5 million in estimated dry hole costs in the drilling of Mary Rose #1. 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 and pipeline facilities. In the event of tropical storms or hurricanes in the Gulf of Mexico while Mary Rose #1 is drilling, our estimated dry hole costs could be significantly greater. As a result of Hurricane Dean, we had to discontinue drilling and went off turn-key operations and “lost” ten days of drilling time at an estimated 8/8ths cost of $1.4 million. COI has a 15.72% working interest and an 11.27% net revenue interest in this well. The prospect is being drilled under a turn-key drilling contract.

The Company’s independent third party engineer estimates the Dutch (Eugene Island 10) and Mary Rose (offshore State of Louisiana) discoveries to have total proved reserves of 226 billion cubic feet equivalent (“Bcfe”) (65 Bcfe net to Contango). A production platform and pipeline, at an estimated 8/8ths cost of $56.0 million, with a capacity of 300 Mmcfe/d is being built by the Company to process and transport anticipated production from the Mary Rose #1 well and from an expected additional three to five wells. The Company expects it will take between seven to nine wells to fully develop its Dutch and Mary Rose discoveries. The platform and pipeline are expected to be delivered by the end of the year and scheduled to be placed into service in May 2008. If successful, the Mary Rose #1 and follow-on developmental wells are anticipated to begin production in May 2008.

In December 2006, COI sold its 25% working interest in Grand Isle 72 to an independent oil and gas company for $7.0 million. The sold property had reserves of approximately 1.9 billion cubic feet equivalent (“Bcfe”), net to COI. The Company recognized a loss of approximately $2.4 million for the fiscal year ended June 30, 2007 as a result of this sale. The Company continues to have an interest in Grand Isle 72 via its investment in COE. COE has a 50% working interest and a 40% net revenue interest in this well.

During July 2006, in the offshore Gulf of Mexico, we drilled two dry holes at West Delta 43 and High Island A-279.

Freeport LNG Development, L.P.

As of June 30, 2007, the Company has invested $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 1.75 billion cubic feet per day (“Bcf/d”) liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas. Startup is expected to occur in the first quarter of calendar year 2008.

In July 2004, Freeport LNG finalized its transaction with The ConocoPhillips Company (“ConocoPhillips”) for the financing, construction and use of the LNG receiving terminal in Freeport, Texas. ConocoPhillips executed a terminal use agreement, 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 is non-recourse to Contango. The Dow Chemical Company (“Dow Chemical”) has also executed a terminal use agreement 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 the general partners, Michael Smith and ConocoPhillips, manage the entire project, with ConocoPhillips, under a construction advisory and management agreement, providing engineering expertise to help manage the construction of the facility. In January 2005 Freeport LNG executed a terminal use agreement with a subsidiary of the Mitsubishi Corporation.

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 1.75 Bcf/d facility commenced on January 17, 2005. Phase I has been restructured to buy back some capacity from ConocoPhillips and add Mitsubishi to Phase I. As of June 30, 2007, the terminal’s Phase I capacity has been sold to ConocoPhillips (0.9 Bcf/d), Dow Chemical (0.5 Bcf/d) and Mitsubishi Corporation (0.15 Bcf/d). Construction



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is expected to be completed by the first quarter of 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 for Phase I is being provided by ConocoPhillips through a construction loan, with debt service being provided by the terminal use agreement with 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 funds from the notes are being used to fund the balance of the Phase I construction of Freeport LNG’s liquefied natural gas regasification terminal. The funds will also be used to fund the development of an integrated natural gas storage salt cavern and a portion of the cost of an expansion of the LNG terminal (“Phase II”). The notes are secured primarily by payments obligated under the terminal use agreement with Dow Chemical.

Phase II expansion of the LNG terminal may include a second LNG unloading dock, additional send-out and additional storage capacity. Freeport LNG submitted a permit application for the expansion to the FERC in May, 2005. FERC approved the expansion permit on September 26, 2006. Expansions of the terminal included in the current authorizations 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, we believe the project will continue through Phase I construction and Phase II pre-development with no further significant funds likely being required from Contango.

Contango Venture Capital Corporation

As of June 30, 2007, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, held a direct investment in three alternative energy portfolio companies: Gridpoint, Inc. (“Gridpoint”), Moblize Inc. (“Moblize”) and Trulite Inc. (“Trulite”). Our investment in Gridpoint is less than a 20% ownership interest and we account for this investment under the cost method. Our investment in Moblize rose above a 20% ownership interest during the three months ended September 30, 2006 when the Company exercised its right pursuant to two warrants, to purchase additional shares of Moblize. We account for this investment under the equity method. Trulite is a publicly traded company. We account for this investment in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 115 (“SFAS 115”), “Accounting for Certain Investments in Debt and Equity Securities”.

Gridpoint, Inc. As of June 30, 2007, CVCC had invested approximately $1.0 million in Gridpoint in exchange for 333,333 shares of Gridpoint preferred stock, which represents an approximate 1.8% ownership interest. Gridpoint’s intelligent energy management products ensure clean, reliable power, increase energy efficiency, and integrate renewable energy. With Gridpoint, home and business owners can protect themselves from power outages, manage their energy online and reduce their carbon footprint.

Moblize Inc. As of June 30, 2007, CVCC had invested $1.2 million in Moblize in exchange for 648,648 shares of Moblize convertible preferred stock, which represents an approximate 33% ownership interest. Moblize develops real time diagnostics and field optimization solutions for the oil and gas and other industries using open-standards based technologies. Moblize has deployed its technology on our Grand Isle 72 well which allows COI to remotely monitor, control and record, in real time, daily production volumes. Moblize is continuing to deploy its technology on oil fields near Houston belonging to Chevron U.S.A. Inc. and on other COI operated wells.

Trulite, Inc. As of June 30, 2007, CVCC had invested $0.9 million in 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, and recently began trading publicly on the over the counter bulletin board under the stock symbol “TRUL.OB”. As a result, we mark-to-market our investment in Trulite based on public pricing. At June 30, 2007, our investment in Trulite had a mark-to-market value of approximately $2.0 million based on a closing stock price of $1.00 per share. Trulite is a startup company with very little trading volume and thus the purchase or sale of relatively small common stock positions may result in disproportionately large increases or decreases in the price of its common stock. An unrealized gain of $0.7 million, net of tax, has been reflected as a component of other comprehensive income at June 30, 2007.

As of June 30, 2007, the Company had loaned Trulite approximately $1.0 million under various promissory notes, with various due dates. The notes initially bear interest at a per annum rate of 11.25%, before changing to Prime plus 3% and then Prime plus 4%. For the fiscal year ended June 30, 2007, the Company earned and accrued approximately $55,000 in interest income from the Trulite notes. Please see Note 18 – Related Party Transactions of Notes to Consolidated Financial Statements included as part of this Form 10-K, for a discussion of our promissory notes with Trulite.

As of June 30, 2007, CVCC owned 25% of Contango Capital Partners Fund, L.P. (the “Fund”). The Fund currently holds a direct investment in two alternative energy companies – Protonex Technology Corporation (“Protonex”) and Jadoo Power Systems (“Jadoo”). We account for our investment in the Fund under the equity method. The Fund, however, accounts for its investment in Protonex in accordance with SFAS 115, and accounts for its investment in Jadoo at fair value in accordance with the AICPA Audit and Accounting Guide, “Investment Companies”.

Protonex Technology Corporation. As of June 30, 2007, the Fund had invested $1.5 million in Protonex in exchange for 2,400,000 shares of Protonex common 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 customers. Protonex trades its common shares on the AIM market of the London Stock Exchange under the stock symbol “PTX.L”. As a result, the Fund marks-to-market its investment in Protonex based on public pricing. At June 30, 2007, the Fund’s investment in Protonex had a mark-to-market value of approximately $4.4 million ($1.1 million net to Contango’s interest).

Jadoo Power Systems. As of June 30, 2007, the Fund has invested approximately $1.2 million and owns 2,200,000 shares of Jadoo common 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. During the fourth quarter of our fiscal year ended June 30, 2007, the management of Jadoo determined that the company was impaired. The Fund therefore incurred an impairment charge of $1.2 million ($0.3 million net to Contango) for the fiscal year ended June 30, 2007, related to our investment in Jadoo.

Marketing and Pricing

The Company currently derives its revenue principally from the sale of natural 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. Market prices are dictated by supply and demand, and the Company cannot predict or control the price it receives for its natural 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:




The domestic and foreign supply of natural gas and oil


Overall economic conditions


The level of consumer product demand


Adverse weather conditions and natural disasters


The price and availability of competitive fuels such as heating oil and coal


Political conditions in the Middle East and other natural gas and oil producing regions


The level of LNG imports


Domestic and foreign governmental regulations


Potential price controls and special taxes

Competition

The Company competes with numerous other companies in 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.

CEO BACKGROUND


Kenneth R. Peak . Mr. Peak is the founder and has been Chairman, Chief Executive Officer and Chief Financial Officer 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 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 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.

Marc Duncan. Mr. Duncan joined Contango 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 in a senior executive 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.

B.A. Berilgen. Mr. Berilgen was appointed a director of Contango in July 2007. Mr. Berilgen has served in a variety of senior positions during his 37 year career. Most recently, he was Chairman, CEO and President of Rosetta Resources Inc., a company he founded in 2005. Prior to that, he was Executive Vice President of Calpine Corp. and President of Calpine Natural Gas L.P. from October 1999 through June 2005. In June 1997, Mr. Berilgen joined Sheridan Energy, a public oil and gas company, as its President and Chief Executive Officer. Mr. Berilgen attended the University of Oklahoma, receiving a B.S. in Petroleum Engineering in 1970 and a M.S. in Industrial Engineering / Management Science.

Jay D. Brehmer . Mr. Brehmer has been a director of Contango since October 2000. Mr. Brehmer is Managing Director of Houston 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.

Charles M. Reimer. Mr. Reimer was elected a director of Contango in 2005. Mr. Reimer is President of Freeport LNG Development, L.P, and has 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 senior 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 P.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 Phoenix Resources Company in 1985 and relocated to Cairo, Egypt, to begin eight years of international assignments in both Egypt and Indonesia. Prior to joining Freeport LNG Development, L.P. in December 2002, Mr. Reimer was President and Chief Executive Officer of Cheniere Energy, Inc.

Steven L. Schoonover. Mr. Schoonover was elected a director of Contango in 2005. Mr. Schoonover currently serves as Chief Executive Officer of Cellxion, L.L.C., a company specializing in construction and installation of telecommunication buildings and towers, as well as the installation of high-tech telecommunication equipment. From 1990 until its sale in November 1997 to Telephone Data Systems, Inc., Mr. Schoonover served as President of Blue Ridge Cellular, Inc., a full-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 the Year, sponsored by Ernst & Young, Inc Magazine and USA Today.

Darrell W. Williams . Mr. Williams has been a director of Contango since 1999. From 2005 through 2007, Mr. Williams was 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. Prior to joining 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.

MANAGEMENT DISCUSSION FROM LATEST 10K

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 in the Arkansas Fayetteville Shale. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator on certain offshore 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 companies focused on commercializing environmentally preferred energy technologies.

Revenues and Profitability. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil and on our ability to find, develop and acquire natural gas and oil reserves that are economically recoverable and the completion and successful operation of our Freeport LNG project. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas and oil activities.

Reserve Replacement . Generally, our producing properties in the Arkansas Fayetteville Shale and offshore in the Gulf of Mexico have high initial production rates, followed by steep declines. As a result, we must locate and develop or acquire new natural gas and oil reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire natural gas and oil reserves.

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.

Use of Estimates. The preparation of our financial statements requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include estimates of remaining proved natural gas and oil reserves and the timing and costs of our future drilling, development and abandonment activities.

Please see “Risk Factors” on page 16 for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations.

Results of Operations

The following is a discussion of the results of our operations for the fiscal year ended June 30, 2007, compared to the fiscal year ended June 30, 2006, and for the fiscal year ended June 30, 2006, compared to the fiscal year ended June 30, 2005.

Revenues. All of our revenues are from the sale of our natural gas and oil production. Our revenues may vary significantly from year to year depending on changes in commodity prices, which fluctuate widely, and production volumes. Our production volumes are subject to wide swings as a result of new discoveries and ongoing geological declines.

Natural Gas and Oil Sales . We reported natural gas and oil sales of approximately $18.7 million for the year ended June 30, 2007, up from approximately $0.9 million reported for the year ended June 30, 2006. This increase is mainly attributable to our Dutch #1 discovery, which began producing in January 2007.

We reported natural gas and oil sales of approximately $0.9 million for the year ended June 30, 2006, down from approximately $1.1 million reported for the year ended June 30, 2005. The slight decrease mainly reflects normal production declines and a decrease in the average price received for natural gas, partially offset by an increase in the average price received for our oil production and newly added reserves and production from our Arkansas Fayetteville Shale play that recently began producing.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the year ended June 30, 2007 was approximately 6,718 Mcf/d, up from approximately 249 Mcf/d for the year ended June 30, 2006. Net oil and NGL production for the period was up from 11 barrels per day to 107 barrels per day. The increase in natural gas, oil and NGL production was primarily the result of our Dutch #1 discovery which began producing in January 2007, our Liberty discovery which began producing in March 2007 and additional production from our Arkansas Fayetteville Shale play. For the year ended June 30, 2007, the price of natural gas was $6.68 per Mcf while the price for oil and NGLs was $59.67 per barrel, compared to $7.15 per Mcf and $61.53 per barrel for the year ended June 30, 2006.

Our net natural gas production for the year ended June 30, 2006 was approximately 249 Mcf/d, up from approximately 195 Mcf/d for the year ended June 30, 2005. Net oil production for the period was down from 22 barrels of oil per day to 11 barrels of oil per day. The increase in natural gas production was primarily the result of additional production from our Arkansas Fayetteville Shale play. The decrease in oil and condensate production is mainly attributable to normal production declines. For the year ended June 30, 2006, prices for natural gas and oil were $7.15 per Mcf and $61.53 per barrel, compared to $8.40 per Mcf and $58.93 per barrel for the year ended June 30, 2005.

Operating Expenses. Operating expenses for the year ended June 30, 2007 were approximately $1.7 million which related to continuing operations from our offshore activities and the Arkansas Fayetteville Shale play. Operating expenses for the year ended June 30, 2006 and June 30, 2005 were $13,350 and $19,683, respectively, which related to continuing operations from our offshore activities.

Exploration Expense. We reported approximately $6.8 million of exploration expenses for the year ended June 30, 2007. Of this amount, approximately $4.4 million was related to unsuccessful wells drilled onshore, approximately $1.4 million was attributable to the cost to acquire and reprocess 3-D seismic data both onshore along the Gulf Coast and offshore in the Gulf of Mexico, and approximately $1.0 million was attributable to the payment of delay rentals.

We reported approximately $8.2 million of exploration expenses for the year ended June 30, 2006. Of this amount, approximately $1.2 million was related to unsuccessful wells drilled during the period, approximately $5.9 million was related to unsuccessful wells drilled in the Gulf of Mexico during the period, approximately $0.5 million was attributable to the cost to acquire and reprocess 3-D seismic data both onshore along the Gulf Coast and offshore in the Gulf of Mexico, and approximately $0.6 million was attributable to the cost of delay rentals.

We reported approximately $5.9 million of exploration expenses for the year ended June 30, 2005. Of this amount, approximately $3.1 million was related to unsuccessful wells drilled in south Texas, approximately $0.8 million was related to unsuccessful wells drilled in the Gulf of Mexico during the period, approximately $1.6 million was attributable to the cost to acquire and reprocess 3-D seismic data both onshore along the Gulf Coast and offshore in the Gulf of Mexico, and $0.4 million was attributable to the cost of delay rentals.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the year ended June 30, 2007 was approximately $3.3 million. For the year ended June 30, 2005, we recorded approximately $0.4 million of depreciation, depletion and amortization. The increase in depreciation, depletion and amortization was primarily attributable to added production from newly added reserves from our Dutch #1, Liberty and Arkansas Fayetteville Shale discoveries.

Depreciation, depletion and amortization for the fiscal years ended June 30, 2006 and 2005 were $0.2 million and $0.4 million, respectively. This decrease was primarily the result of normal production declines.

Impairment of Natural Gas and Oil Properties. We reported an impairment of natural gas and oil properties of approximately $0.2 million for the year ended June 30, 2007. This was attributable to a write-down of costs on the Alta-Ellis #1 well in December 2006.

We reported an impairment of natural gas and oil properties of approximately $0.7 million for the year ended June 30, 2006. These related to impairment of offshore properties held by REX and COE. When Contango acquired an additional interest in REX and COE, the purchase price was allocated to several prospects. Specifically, $0.3 million related to our Main Pass 221 prospect and $0.3 million related to our West Delta 43 prospect were impaired because they were both determined to be dry holes during the period; and $0.1 million relating to our East Cameron 107 prospect was impaired as a result of the expiration of its lease.

We reported an impairment of natural gas and oil properties of approximately $0.2 million for the year ended June 30, 2005. This was attributable in part to a $0.1 million write-down of costs associated with offshore lease properties owned by our partially owned subsidiary MOE, of which Contango owns 50%. The remaining $0.1 million was attributable to a write-down of costs associated with a small Barnett Shale exploratory play undertaken during the summer of 2003 that had only marginal success.

General and Administrative Expenses. General and administrative expenses for the year ended June 30, 2007 were approximately $6.8 million, up from $4.8 million for the year ended June 30, 2006. Major components of general and administrative expenses for the year ended June 30, 2007 included approximately $4.4 million in salaries, benefits and bonuses (includes $1.5 million in non-cash expenses related to the cost of expensing stock options), $1.2 million in office administration and other expenses, $0.3 million in insurance costs, $0.5 million in accounting and tax services, and $0.4 million in legal and other administrative expenses, These sales bring forward future revenues and cash flows, but our longer term liquidity could be impaired to the extent our exploration efforts are not successful in generating new discoveries, production, revenues and cash flows. Additionally, our longer term liquidity could be impaired due to the decrease in our inventory of producing properties that could be sold in future periods. Further, as a result of these property sales the Company’s ability to collateralize bank borrowings is reduced which increases our dependence on more expensive mezzanine debt and potential equity sales. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.

The table below sets forth the proceeds received from property sales in each of the fiscal years ended June 30, 2005, 2006 and 2007, the impact of these sales on our developed reserve quantities, and a measure of our developed reserves held at the end of each such fiscal year. Please see the reserve activity reported in the Supplemental Oil and Gas Disclosures on pages F-27 and F-28 for a more detailed discussion regarding our standardized measure.

The Company had no discontinued operations for the fiscal year ended June 30, 2007. For fiscal year 2006, however, discontinued operations contributed $8.3 million in operating cash flows, $9.9 million in investing cash flows and $1.6 million in financing cash flows.

Operating Activities. Cash flow from operating activities provided approximately $4.0 million in cash for the year ended June 30, 2007 compared to $9.5 million for the same period in 2006. This decrease in cash from operating activities is primarily attributable to higher general and administrative costs, higher operating expenses and higher interest expense.

Our operating activities provided approximately $9.5 million in cash for the year ended June 30, 2006 compared to $4.9 million for the same period in 2005. The increase in cash from operating activities is primarily attributable to increased production as we redeployed the money raised in our December 2004 property sale to Edge Petroleum Corporation (“Edge”) to drill and develop new onshore wells.

Investing Activities. Cash flows used in investing activities for the year ended June 30, 2007 were approximately $55.1 million, compared to $23.7 million used in investing activities for the year ended June 30, 2006. This increase in cash flows used in investing activities was due primarily to $77.5 million used in natural gas and oil exploration and development expenses, offset by selling approximately $16.0 million of short-term investments and the sale of COI’s 25% interest in Grand Isle 72 for $7.0 million.

Cash flows used in investing activities for the year ended June 30, 2006 were approximately $23.7 million, compared to cash flows provided by investing activities for the year ended June 30, 2005 of approximately $4.3 million. This increase in capital expenditures was due primarily to investing $34.1 million in natural gas and oil properties with funds received from our sale to Edge in December 2004, slightly offset by selling approximately $7.0 million of short-term investments. Additionally, we invested $2.4 million in our Freeport LNG project and alternative energy companies, $1.0 million on acquiring additional offshore interests and $7.5 million on acquiring additional ownership interests in REX and COE.

Financing Activities. Cash flows provided by financing activities for the year ended June 30, 2007 were approximately $47.0 million, compared to $20.5 million for the same period in 2006. This increase in cash flow is primarily attributable to raising approximately $28.8 million from the issuance of our Series E convertible preferred equity securities, net of issuance costs, and $8.5 million in borrowings by our affiliates.

Cash flows provided by financing activities for the year ended June 30, 2006 were approximately $20.5 million, compared to cash flows used in financing activities for the year ended June 30, 2005 of approximately $5.6 million. This increase in cash flow is primarily attributable to borrowing $10.0 million of long term debt and raising approximately $9.6 million from the issuance of our Series D convertible preferred equity securities, net of issuance costs.

Capital Budget. For fiscal year 2008, our capital expenditure budget calls for us to invest a total of $55.6 million, as we continue to develop our Arkansas Fayetteville Shale play, bring Dutch #3 to production, drill additional developmental wells on our Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) prospects, build an associated platform and pipeline and drill at least one additional wildcat exploration offshore well unrelated to Dutch or Mary Rose.

Of the $55.6 million fiscal year 2008 capital expenditure budget, approximately $30.0 million is anticipated to be invested in offshore activities. Our budget calls for us to invest approximately $5.6 million for production and pipeline facilities for developing Dutch #3 and bringing it to production, approximately $3.8 million to drill and complete Mary Rose #1, approximately $8.2 million for a platform and 20-inch, 20-mile pipeline we are building at Eugene Island 11, approximately $10.1 million in projected follow-on developmental wells, and approximately $2.3 million in future delay rentals and drilling an offshore wildcat exploration well unrelated to Dutch and Mary Rose. In addition, depending on our available cash flow, we could increase our capital budget for additional offshore wildcat exploration wells.

Of the $55.6 million fiscal year 2008 capital expenditure budget, $25.6 million is expected to be invested in onshore activities. In the Arkansas Fayetteville Shale, we have received Authority for Expenditure (“AFEs”) and committed to a total of 142 wells in this play as of July 31, 2007. Of these 142 wells, 13 are operated by Alta and 129 are operated by a third party independent oil and gas exploration company (“Integrated Wells”). Our working interest and net revenue interest have averaged approximately 11% and 8.8%, respectively, in these 142 wells.

In addition to the 13 Alta wells, we are budgeting to receive one AFE from Alta per month for wells to be drilled during fiscal year 2008, and therefore expect to drill 12 Alta wells during fiscal year 2008 at a cost of $15.6 million. This includes drilling, fracture stimulating, completion and hookup costs for the wells. Additionally, we expect to invest $1.3 million to bring the Deltic #1-8H and Alta-Deltic #2-8H to production. We estimate we will have an average working interest of approximately 50.0% and a net revenue interest of approximately 40.0% in these 25 Alta wells.

In addition to the 129 Integrated Wells for which we have received an AFE, we are budgeting to receive four AFEs for Integrated Wells per month during fiscal year 2008 for a total of 177 Integrated Wells. We anticipate having between 120 to 130 producing Integrated Wells by December 2007. Our capital budget for Integrated Wells assumes we will invest $8.7 million in Integrated Wells during fiscal year 2008, assuming we drill four wells per month. We estimate we will have an average working interest of 6.5%, and a net revenue interest of 5.3% in these 177 Integrated Wells.

Freeport LNG closed a $383.0 million private placement note issuance in December 2005, and we believe the LNG project will continue through Phase I construction and Phase II pre-development expansion with no further significant funds being required from Contango.

As of August 31, 2007, we have approximately $1.5 million in cash, cash equivalents, and short term investments. We have $20.0 million in long-term debt outstanding at our wholly-owned subsidiary, Contango Sundance, Inc. (“Sundance”), which is guaranteed by the Company and secured by the stock of Sundance, and an additional $30.0 million of unutilized borrowing capacity available to the Company.

Income Taxes. During the year ended June 30, 2007, we paid $0.4 million in estimated income taxes.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

Three Months Ended December 31, 2007 Compared to Three Months Ended December 31, 2006

Natural Gas, Oil and Natural Gas Liquids (“NGL”) Sales. We reported revenues of approximately $21.2 million for the three months ended December 31, 2007, compared to revenues of approximately $0.9 million for the three months ended December 31, 2006. This increase is mainly attributable to our Dutch #1 discovery which began producing in January 2007, our Dutch #2 discovery which began producing in July 2007, our Dutch #3 discovery which began producing in November 2007, and increased production from our Arkansas Fayetteville Shale play.

For the three months ended December 31, 2007 and December 31, 2006, prices for natural gas were $7.32 per thousand cubic feet (“Mcf”) and $7.45 per Mcf, respectively, while the blended price for oil and NGLs was $86.85 per barrel and $58.33 per barrel, respectively.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the three months ended December 31, 2007 was approximately 26.6 Mmcf/d, up from approximately 1.1 Mmcf/d for the three months ended December 31, 2006. Net oil and NGL production for the comparable periods also increased from approximately ten barrels per day to approximately 400 barrels per day. This increase in natural gas production is principally attributable to Dutch #1 which began producing in January 2007, Dutch #2 which began producing in July 2007, Dutch #3 which began producing in November 2007, and increased production from our Arkansas Fayetteville Shale play. The increase in oil and NGL production is principally attributable to our Dutch discoveries.

Operating Expenses. Lease operating expenses for the three months ended December 31, 2007 and the three months ended December 31, 2006 were $959,232 and $144,702, respectively. These expenses are related to our increased activities in the Arkansas Fayetteville Shale play and the Gulf of Mexico.

Exploration Expense. We reported $451,440 of exploration expenses for the three months ended December 31, 2007 and $496,123 of exploration expenses for the three months ended December 31, 2006. These costs are attributable to the cost of various geological and geophysical activities, seismic data, dry holes and delay rentals.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended December 31, 2007 was approximately $1.8 million. For the three months ended December 31, 2006, we recorded $292,192 of depreciation, depletion and amortization. The increase is the result of production from our Dutch #1 well which began producing in January 2007, our Dutch #2 well which began producing in July 2007, our Dutch #3 well which began producing in November 2007, and increased production from our Arkansas Fayetteville Shale play.

Impairment of Natural Gas and Oil Properties. No impairment of natural gas and oil properties was incurred during the three months ended December 31, 2007. Approximately $0.2 million of impairment was reported for the three months ended December 31, 2006. This was attributable to a write-down of costs of the Alta-Ellis #1 well in December 2006.

General and Administrative Expenses. General and administrative expenses for the three months ended December 31, 2007 and the three months ended December 31, 2006 were approximately $1.8 million and $1.4 million, respectively.

Major components of general and administrative expenses for the three months ended December 31, 2007 included approximately $0.8 million in salaries and benefits, approximately $0.5 million in legal, accounting, engineering and other professional fees, $0.1 million in insurance costs, and $0.4 million related to the cost of expensing stock options and stock grant compensation.

Major components of general and administrative expenses for the three months ended December 31, 2006 included approximately $0.4 million in salaries and benefits, $0.3 million in legal, accounting, engineering and other professional fees, $0.3 million in office administration expenses, and $0.4 million related to the cost of expensing stock options and stock grant compensation.

Interest Expense. We reported interest expense of $1.3 million for the three months ended December 31, 2007, compared to interest expense of $390,434 for the three months ended December 31, 2006. The higher level of interest expense is attributable to higher levels of bank debt outstanding by the Company and its affiliates during such period.

Interest Income. We reported interest income of $484,195 for the three months ended December 31, 2007. This compares to the $155,483 of interest income reported for the three months ended December 31, 2006. The increase is due to additional interest income from loans made to affiliates.

Gain (Loss) on Sale of Asset and Other. For the three months ended December 31, 2007, we reported a gain on sale of asset and other of approximately $156.5 million. Of this amount, approximately $156.4 million relates to the sale of our Western core Arkansas Fayetteville Shale properties. For the three months ended December 31, 2006, we reported a loss on sale of asset and other of approximately $1.4 million resulting from the December 2006 sale of COI’s 25% working interest in the Grand Isle 72 well (“Liberty”).

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