UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended June 30, 2007

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from        to      

Commission file number 001-16317

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

Delaware	95-4079863
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

3700 Buffalo Speedway, Suite 960

Houston, Texas 77098

(Address of principal executive offices)

(713) 960-1901

(Registrant’s telephone number, including area code)

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

Common Stock, Par Value $0.04 per share American Stock Exchange

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one).    Large accelerated filer  ¨      Accelerated filer  x      Non-accelerated filer  ¨

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

At December 31, 2006, the aggregate market value of the registrant’s common stock held by non-affiliates (based upon the closing sale price of shares of such common stock as reported on the American Stock Exchange) was $280,884,573. As of August 31, 2007, there were 16,015,138 shares of the registrant’s common stock outstanding.

Documents Incorporated by Reference

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED JUNE 30, 2007

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business
	Overview	1
	Our Strategy	1
	Exploration Alliances with JEX and Alta	2
	Onshore Exploration and Properties	2
	Offshore Gulf of Mexico Exploration Joint Ventures	3
	Contango Operators, Inc.	5
	Offshore Properties	7
	Freeport LNG Development, L.P.	9
	Contango Venture Capital Corporation	10
	Marketing and Pricing	11
	Competition	11
	Governmental Regulations	12
	Employees	14
	Directors and Executive Officers	14
	Corporate Offices	16
	Code of Ethics	16
	Available Information	16
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	25
Item 2.	Description of Properties
	Production, Prices and Operating Expenses	25
	Development, Exploration and Acquisition Capital Expenditures	26
	Drilling Activity	26
	Exploration and Development Acreage	26
	Productive Wells	27
	Natural Gas and Oil Reserves	28
Item 3.	Legal Proceedings	29
Item 4.	Submission of Matters to a Vote of Security Holders	29
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	33
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Overview	34
	Results of Operations	34
	Capital Resources and Liquidity	37
	Off Balance Sheet Arrangements	39
	Contractual Obligations	40
	Long-Term Debt	40
	Application of Critical Accounting Policies and Management’s Estimate	40
	Recent Accounting Pronouncements	42
Item 7A.	Quantitative and Qualitative Disclosure about Market Risk	42
Item 8.	Financial Statements and Supplementary Data	43
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	43
Item 9A.	Controls and Procedures	43
Item 9B.	Other Information	45

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	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	45
Item 11.	Executive Compensation	45
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	45
Item 13.	Certain Relationships and Related Transactions, and Director Independence	45
Item 14.	Principal Accountant Fees and Services	45
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	45

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:

• Our financial position

• Business strategy, including outsourcing

• Meeting our forecasts and budgets

• Anticipated capital expenditures

• Drilling of wells

• Natural gas and oil production and reserves

• Timing and amount of future discoveries (if any) and production of natural gas and oil

• Operating costs and other expenses

• Cash flow and anticipated liquidity

• Prospect development

• Property acquisitions and sales

• Development, construction and financing of our liquefied natural gas (“LNG”) receiving terminal

• Investments in alternative energy

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:

• Low and/or declining prices for natural gas and oil

• Natural gas and oil price volatility

• Operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms, pipelines and gas processing facilities

• The risks associated with acting as the operator in drilling deep high pressure wells in the Gulf of Mexico

• The risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes, especially in prospects in which the Company has made a large capital commitment relative to the size of the Company’s capitalization structure

• The timing and successful drilling and completion of natural gas and oil wells

• Availability of capital and the ability to repay indebtedness when due

• Availability of rigs and other operating equipment

• Ability to raise capital to fund capital expenditures

• Timely and full receipt of sale proceeds from the sale of our production

• The ability to find, acquire, market, develop and produce new natural gas and oil properties

• Interest rate volatility

• Uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures

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• Operating hazards attendant to the natural gas and oil business

• Downhole drilling and completion risks that are generally not recoverable from third parties or insurance

• Potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline mishaps

• Weather

• Availability and cost of material and equipment

• Delays in anticipated start-up dates

• Actions or inactions of third-party operators of our properties

• Actions or inactions of third-party operators of pipelines or processing facilities

• Ability to find and retain skilled personnel

• Strength and financial resources of competitors

• Federal and state regulatory developments and approvals

• Environmental risks

• Worldwide economic conditions

• Ability of LNG to become a competitive energy supply in the United States

• Ability to fund our LNG project, cost overruns and third party performance

• Successful commercialization of alternative energy technologies

• Drilling and operating costs, production rates and ultimate reserve recoveries in our Arkansas Fayetteville Shale play

• Drilling and operating costs, production rates and ultimate reserve recoveries in our Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) acreage.

• The ability of Republic Exploration, LLC (“REX”), our partially-owned subsidiary, to fund its working interest commitment in our Dutch and Mary Rose development.

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” referred to on page 16 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 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.

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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

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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

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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.

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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

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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.

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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 August 31, 2007:

Area/Block	WI	NRI	Status
Contango Operators, Inc:
Eugene Island 113B	0%	1.7%	Awaiting installation of compression
Eugene Island 10 #1	16.0%	14.7%	Producing
Eugene Island 10 #2	16.0%	14.7%	Producing
Contango Offshore Exploration LLC:
Ship Shoal 358, A-3 well	10.0%	7.7%	Awaiting Re-completion
Grand Isle 72	50.0%	40.0%	Producing
Republic Exploration LLC:
Eugene Island 113B	0%	3.3%	Awaiting installation of compression
West Delta 36	(1)	(1)	Producing
Eugene Island 10 #1 Eugene Island 10 #2	56.9% 56.9%	52.1% 52.1%	Producing Producing

(1) REX has a 3.67% ORRI before payout and, at its option, may elect either a 5.0% ORRI or 25% WI after payout.

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 August 31, 2007:

Area/Block	WI	NRI	Status
Republic Exploration LLC:
Vermilion 154	(2)	(2)	Drilling expected by summer 2008
Vermillion 73	(3)	(3)	Determined to be a dry hole
South Marsh Island 247	(4)	(4)	Determined to be a dry hole
Contango Offshore Exploration LLC:
East Breaks 369	-	-	Determined to be a dry hole
East Breaks 370	(5)	(5)	No drilling date has been determined yet
Vermilion 154	(2)	(2)	Drilling expected by summer 2008

(2) REX and COE will split a 25% back-in WI after payout.

(3) Record title interest in lease has been assigned to a third party.

(4) Record title interest in lease has been assigned to a third party. REX has reserved a 5% of 8/8ths ORRI before payout.

(5) Farmee has until September 1, 2008 to decide if East Breaks 370 will be drilled. COE will receive a 3.67% ORRI before project payout and a 6.67% ORRI after project payout.

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Leases.  The following table sets forth the working interests owned by Contango and related entities in the Gulf of Mexico as of August 31, 2007:

Area/Block	WI		Lease Date
Contango Operators, Inc.:
West Cameron 174	10.0	%	Jul-03
Grand Isle 63	25.0	%	May-04
Grand Isle 73	25.0	%	May-04
West Delta 43	35.0	%	May-04
S-L 18640 (LA)	15.7	%	Jul-05
S-L 18860 (LA)	15.7	%	Jan-06
Ship Shoal 14	37.5	%	May-06
Ship Shoal 25	37.5	%	May-06
South Marsh Island 57	37.5	%	May-06
South Marsh Island 59	37.5	%	May-06
South Marsh Island 75	37.5	%	May-06
South Marsh Island 282	37.5	%	May-06
Grand Isle 70	3.65	%	Jun-06
West Delta 77	25.0	%	Jun-06
Vermilion 194	37.5	%	Jul-06
Eugene Island 10	16.0	%	Nov-06
S-L 19261 (LA)	15.7	%	Feb-07
S-L 19266 (LA)	15.7	%	Feb-07
S-L 19396 (LA)	15.7	%	Jun-07
Area/Block	WI		Lease Date
Republic Exploration LLC:
West Cameron 174	90.0	%	Jul-03
High Island 113	100.0	%	Oct-03
South Timbalier 191	50.0	%	May-04
Vermilion 36	100.0	%	May-04
Vermilion 109	100.0	%	May-04
Vermilion 134	100.0	%	May-04
West Cameron 179	100.0	%	May-04
West Cameron 185	100.0	%	May-04
West Cameron 200	100.0	%	May-04
West Delta 18	100.0	%	May-04
West Delta 33	100.0	%	May-04
West Delta 34	100.0	%	May-04
West Delta 43	30.0	%	May-04
Ship Shoal 220	50.0	%	Jun-04
South Timbalier 240	50.0	%	Jun-04
West Cameron 133	100.0	%	Jun-04
West Cameron 80	100.0	%	Jun-04
West Cameron 167	100.0	%	Jun-04
Eugene Island 76	0	%	Jul-04
Vermilion 130	100.0	%	Jul-04
West Cameron 107	100.0	%	May-05
Eugene Island 168	50.0	%	Jun-05
S-L 18640 (LA)	55.7	%	Jul-05
S-L 18860 (LA)	55.7	%	Jan-06
High Island A243	75.0	%	Jan-06
South Marsh Island 57	50.0	%	May-06
South Marsh Island 59	50.0	%	May-06
South Marsh Island 75	50.0	%	May-06
South Marsh Island 282	50.0	%	May-06
Ship Shoal 14	50.0	%	May-06
Ship Shoal 25	50.0	%	May-06
West Delta 77	50.0	%	Jun-06
Vermilion 194	50.0	%	Jul-06
High Island A196	100.0	%	Oct-06
High Island A197	100.0	%	Oct-06
High Island A198	100.0	%	Oct-06
Eugene Island 10	56.9	%	Nov-06
S-L 19261 (LA)	55.7	%	Feb-07
S-L 19266 (LA)	55.7	%	Feb-07
S-L 19396 (LA)	55.7	%	Jun-07

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Area/Block	WI		Lease Date
Contango Offshore Exploration LLC:
Ship Shoal 358	10	%	Jun-98
Viosca Knoll 167	100.0	%	May-03
Vermilion 231	100.0	%	May-03
Viosca Knoll 161	33.3	%	Jul-03
Eugene Island 209	100.0	%	Jul-03
High Island A16	100.0	%	Dec-03
East Breaks 283	100.0	%	Dec-03
South Timbalier 191	50.0	%	May-04
Grand Isle 63	50.0	%	May-04
Grand Isle 72	50.0	%	May-04
Grand Isle 73	50.0	%	May-04
Ship Shoal 220	50.0	%	Jun-04
South Timbalier 240	50.0	%	Jun-04
Viosca Knoll 118	33.3	%	Jun-04
Viosca Knoll 475	100.0	%	May-05
Eugene Island 168	50.0	%	Jun-05
East Breaks 366	100.0	%	Nov-05
East Breaks 410	100.0	%	Nov-05
East Breaks 167	75.0	%	Dec-05
High Island A311	75.0	%	Dec-05
East Breaks 166	75.0	%	Jan-06
High Island A342	75.0	%	Jan-06
Ship Shoal 263	75.0	%	Jun-06
Grand Isle 70	52.6	%	Jun-06
Viosca Knoll 119	50.0	%	Jun-06
Viosca Knoll 383	100.0	%	Jun-06
Area/Block	WI		Lease Date
Magnolia Offshore Exploration LLC:
Viosca Knoll 161	16.7	%	Jul-03
Viosca Knoll 118	16.7	%	Jun-04

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.

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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.

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Governmental 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 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.

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.

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

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

Government Regulation of LNG Operations.  Our LNG operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and other laws. Among other matters, these laws require the acquisition of certain permits and other authorizations before commencement of construction and operation of an LNG receiving terminal. Failure to comply with such rules, regulations and laws could result in substantial penalties.

In order to site, construct and operate the Freeport LNG receiving terminal, authorization from the FERC under Section 3 of the Natural Gas Act of 1938 (the “NGA”) was required. The FERC permitting process includes detailed engineering and design work, extensive data gathering, preparation and final issuance of an Environmental Impact Statement under the National Environmental Policy Act, and public notices and opportunities for public hearings relating to:

• Siting requirements

• Design standards

• Construction standards

• Equipment, operations and maintenance

• Personnel qualifications and training

• Fire protection

• Security

The FERC approved the project in June 2004. 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 9.6 mile pipeline, together with related facilities, in Brazoria County, Texas. In September 2006, Freeport LNG received FERC authorization to expand the terminal’s capacity. 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

13

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 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.

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 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 and independent third party engineering firms to calculate our reserves.

Directors and Executive Officers

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

Name	Age	Position
Kenneth R. Peak	62	Chairman, President, Chief Executive Officer,
		Chief Financial Officer, Secretary and Director
Lesia Bautina	36	Senior Vice President and Controller
Sergio Castro	38	Vice President and Treasurer
Marc Duncan	54	President & Chief Operating Officer, Contango Operators, Inc.
B.A. Berilgen	59	Director
Jay D. Brehmer	42	Director
Charles M. Reimer	62	Director
Steven L. Schoonover	62	Director
Darrell W. Williams	64	Director

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.

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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.

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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.

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. Beginning in November 2006, each outside director of the Company receives a quarterly retainer of $8,000 payable in cash and $36,000 annually payable in Company 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 cash payment of $3,000. 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. On September 30, 2006 we extended the term of our lease agreement for an additional 60 months, commencing November 1, 2006, with a termination date of October 31, 2011.

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 at www.contango.com.

Available Information

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

Item 1A.  Risk Factors

In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating 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 no ability to control the prices that we receive for natural gas and oil. Natural gas and oil prices fluctuate widely, and low prices would have a material adverse effect on our revenues, profitability and growth.

Our revenues, profitability and future growth depend significantly on natural gas and crude oil prices. Prices received affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and 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:

• The domestic and foreign supply of natural gas and oil.

• Overall economic conditions.

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• 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.

• Access to pipelines and gas processing plants.

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

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

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

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

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

Our business plan, which includes participation in 3-D seismic shoots, lease acquisitions, the drilling of exploration prospects and producing property acquisitions, has required and is expected to continue to 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 frequently obtain capital through the sale of our producing properties.

The Company, since its inception in September 1999, has raised $87.0 million in proceeds from eight separate property sales. 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.

We assume additional risk 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. COI is currently the operator for our

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Dutch and Mary Rose prospects. 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 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 significant 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.

Most of our revenues and production are from our Dutch wells and we depend upon outside third parties to operate and maintain our production, pipelines and processing facilities.

We depend upon the services of others to drill and complete our wells, and operate production platforms, pipelines, gas processing facilities and the infrastructure required to produce and market our natural gas, condensate and oil. As a result, we have no control over how frequently and how long our production is shut-in when production problems, weather and other production shut-ins occur. As we have ramped up production at our Dutch #1 and Dutch #2 wells, and as we prepare to begin production at our Dutch #3 well, we have had to increase the production handling capacity of related downstream infrastructure necessary to produce these wells at their designed flow rates. As a consequence, we have incurred a number of production shut-ins which have negatively affected our near term revenues and cash flow.

Repeated production shut-ins can possibly damage our well bores.

Our Dutch #1 and Dutch #2 well bores are required to be shut-in from time to time due to a combination of weather, mechanical problems and shut-ins necessary to upgrade and increase the production handling capacity at related downstream platform, gas processing and pipeline infrastructure. In addition to negatively impacting our near term revenues and cash flow, repeated production shut-ins could have the potential to damage our well bores if repeated excessively or not executed properly. The loss of a well bore due to damage could require us to drill additional wells to recover our reserves.

We have significant resources committed to our Arkansas Fayetteville Shale play.

Our Arkansas Fayetteville Shale play proved reserves at June 30, 2007 were approximately 15.2 Bcf. Since inception, we have expended approximately $48.0 million in the Fayetteville Shale play ($9.5 million in lease acquisitions, $34.2 million in drilling and completion activities and $4.3 million in dry hole costs), while our revenues from the play from inception through the production month of June 2007 have totaled only $4.2 million. There can be no assurance that our drilling activity in this area will produce economically feasible wells. Our capital budget for fiscal year 2008 calls for us to invest an additional $25.6 million in the Arkansas Fayetteville Shale. This represents approximately 46% of our total CAPEX budget for the next twelve months. We intend to continue to borrow significant capital against anticipated revenues and production, and should the wells not perform as expected, we could encounter difficulty repaying this debt. It is early in the exploration and development of this play, there is a lack of oil field service infrastructure in the area, and we are still learning how to most efficiently drill, complete, fracture stimulate and produce these wells. Some of our wells have taken

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considerably longer than expected to drill, and we have had significant cost overruns. All of our wells are operated by others and as a result, we have a limited ability to exercise influence over operations or their associated costs.

We are highly dependent on the lending availability of a single company.

Our $30.0 million Term Loan Agreement and REX’s $50.0 million demand note are with the same private investment firm. Contango had no amounts outstanding under the Term Loan Agreement and REX had borrowed $31.0 million under its demand note as of August 31, 2007. Should the private investment firm encounter difficulties funding future requested advances, some portion or all of the $49.0 million of capital that remains unfunded may no longer be available. In that case, we would be forced to seek alternative and possibly more expensive financing, which may or may not be available.

REX’s $50 million note is payable upon demand by the lender.

REX’s $50.0 million demand note with the private investment firm is payable upon demand. Should the private investment firm decide to call the note, REX does not have the funds available to repay its borrowings. In that case, REX would be forced to seek alternative and possibly more expensive financing, which may or may not be available, or risk losing the assets it has pledged as collateral, including its interest in the Dutch and Mary Rose prospects.

We have outsourced the marketing of our production and the vast majority of our revenues are from one purchaser, Cokinos Energy Corporation.

A significant portion of the Company’s production is sold to Cokinos Energy Corporation. These sales to Cokinos Energy Corporation are secured with letters of credit.

Our capital exploration is focused on two highly capital intensive prospect areas which increases our risk of incurring significant losses.

Beginning in the spring of 2005, we have continued to increase our capital investment in just two exploration prospects, our onshore Arkansas Fayetteville Shale prospect and our offshore Gulf of Mexico prospects. Both of these investments represent a major increase in the risk profile of the Company.

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 being constructed in Freeport, Texas. The LNG project received approval from 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 1.75 Bcf/d facility commenced on January 17, 2005. Freeport LNG received FERC authorization in September 2006 for an expansion that would increase the permitted capacity from its current level of 1.75 Bcf/d up to as much as 4.0 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.

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If we are not able to fund or finance our 10% ownership in the LNG receiving terminal in Freeport, Texas, including any expansion of the terminal, we may lose our 10% investment in the project.

A majority of the Freeport LNG construction costs is being provided by ConocoPhillips. Upon any significant increase in construction costs to complete construction of the receiving terminal or upon a call to fund construction of the 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 or be forced to sell our interest in an untimely fashion or on less than favorable terms.

If we default on our loan from the Royal Bank of Scotland plc we could lose our 10% investment in the LNG receiving terminal 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 terminal. If an event of default occurs under the term loan agreement, we could lose our investment in the Freeport LNG terminal.

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, the 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 engineers 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. Most of the producing wells included in our reserve report have produced

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for a relatively short period of 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 will likely differ materially from those used in the pre-tax net present value estimate.

The proved reserves assigned to our Dutch and Mary Rose discoveries have only two producing well bores that, as of August 31, 2007, had only seven months of production history. Reserve assessments based on only two well bores with limited production history are subject to greater risk of downward revision than multiple well bores from a mature producing reservoir.

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 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 significant risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

• Unexpected drilling conditions.

• Blowouts, fires or explosions with resultant injury, death or environmental damage.

• Pressure or irregularities in formations.

• Equipment failures or accidents.

• Tropical storms, hurricanes and other adverse weather conditions.

• Compliance with governmental requirements and laws, present and future.

• Shortages or delays in the availability of drilling rigs and the delivery of equipment.

• Our turnkey drilling contracts reverting to a day rate contract which would significantly increase the cost and risk to the Company.

• Problems at third party operated platforms, pipelines and gas processing facilities over which we have no control.

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.

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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:

• Blowouts, fires and explosions.

• Surface cratering.

• Uncontrollable flows of underground natural gas, oil or formation water.

• Natural disasters.

• Pipe and cement failures.

• Casing collapses.

• Stuck drilling and service tools.

• Abnormal pressure formations.

• Environmental hazards such as natural gas leaks, oil spills, pipeline ruptures or discharges of toxic gases.

• Capacity constraints, equipment malfunctions and other problems at third party operated platforms, pipelines and gas processing plants over which we have no control.

• Repeated shut-ins of our well bores could significantly damage our well bores.

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

• Injury or loss of life.

• Reservoir damage.

• Severe damage to and destruction of property or equipment.

• Pollution and other environmental damage.

• Clean-up responsibilities.

• Regulatory investigations and penalties.

• Suspension of our operations or repairs necessary to resume operations.

Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizing 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 our production should be shut-in during a period when NYMEX natural gas prices increase, 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 and equipment malfunctions on the platforms, gathering systems, pipelines and gas plants that transport and process our natural gas and oil.

All of our natural gas and oil is transported through gathering systems, pipelines and processing plants, and in some cases offshore platforms, which we do not own. Transportation capacity on gathering system

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pipelines and platforms 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, processing plants, platforms 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. Further, repeated shut-ins of our wells could result in damage to our well bores that would impair our ability to produce from these wells and could result in additional wells being required to produce our reserves.

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 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 title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect. It may also happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.

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

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

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

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

• Require that we obtain permits before commencing drilling.

• Restrict the substances that can be released into the environment in connection with drilling and production activities.

• Limit or prohibit drilling activities on protected areas, such as wetlands or wilderness areas.

• Require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells.

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

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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:

• Timing and amount of capital expenditures.

• The operator’s expertise and financial resources.

• Approval of other participants in drilling wells.

• Selection of technology.

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. The successful acquisition of natural gas and oil properties requires an assessment of:

• Recoverable reserves.

• Exploration potential.

• Future natural gas and oil prices.

• Operating costs.

• Potential environmental and other liabilities and other factors.

• Permitting and other environmental authorizations required for our operations.

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:

• Problems integrating the purchased operations, personnel or technologies.

• Unanticipated costs.

• Diversion of resources and management attention from our exploration business.

• Entry into regions or markets in which we have limited or no prior experience.

• Potential loss of key employees, particularly those of the acquired organization.

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

24

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:

• Designate the terms of and issue new series of preferred stock.

• Limit the personal liability of directors.

• Limit the persons who may call special meetings of stockholders.

• Prohibit stockholder action by written consent.

• Establish advance notice requirements for nominations for election of the board of directors and for proposing matters to be acted on by stockholders at stockholder meetings.

• Require us to indemnify directors and officers to the fullest extent permitted by applicable law.

• Impose restrictions on business combinations with some interested parties.

Our common stock is thinly traded.

Contango has approximately 16 million shares of common stock outstanding, held by approximately 120 holders of record. Directors and officers own or have voting control over approximately 3.3 million 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.

Item 1B.  Unresolved Staff Comments

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, oil and natural gas liquids (“NGLs”) for the periods indicated. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil, condensate or NGL is the energy equivalent of six thousand cubic feet (“Mcf”) of natural gas.

	Year Ended June 30,
	2007		2006		2005
Production:
Natural gas (million cubic feet)		2,452		91		71
Oil, condensate and NGLs (thousand barrels)		39		4		8
Total (million cubic feet equivalent)		2,686		115		119
Natural gas (thousand cubic feet per day)		6,718		249		195
Oil, condensate and NGLs (barrels per day)		107		11		22
Total (thousand cubic feet equivalent per day)		7,360		315		327
Average sales price:
Natural gas (per thousand cubic feet)	$	6.68	$	7.15	$	8.40
Oil, condensate and NGLs (per barrel)	$	59.67	$	61.53	$	58.93
Total (per thousand cubic feet equivalent)	$	6.96	$	8.00	$	9.15
Selected data per Mcfe:
Total lease operating expenses	$	0.62	$	0.11	$	0.17
General and administrative expenses	$	2.55	$	41.40	$	30.01
Depreciation, depletion and amortization of natural gas and oil properties	$	1.08	$	2.03	$	2.96

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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:

	Year Ended June 30,
	2007		2006		2005
Property acquisition costs:
Unproved	$	3,571,830	$	14,609,232	$	248,634
Proved		-		-		-
Exploration costs		72,888,603		19,529,607		9,428,002
Developmental costs		1,453,066		590,395		-
Capitalized interest		1,083,693		149,365		-
Total costs	$	78,997,192	$	34,878,599	$	9,676,636

Drilling Activity

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

	Year Ended June 30,
	2007		2006		2005
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells:
Productive (onshore)	60	9.9	11	2.0	4	1.4
Productive (offshore)	4	1.6	1	0.6	-	-
Non-productive (onshore)	4	0.6	3	2.8	8	3.6
Non-productive (offshore)	1	0.4	2	0.9	1	0.1
Total	69	12.5	17	6.3	13	5.1

(1) The Company has not drilled any development wells since fiscal year 2004, when it drilled one gross development well (0.8 net developmental wells). The well was a productive well.

Exploration and Development Acreage

Our principal natural gas and oil properties consist of natural gas and oil leases. The following table indicates our interests in developed and undeveloped acreage as of June 30, 2007:

	Developed Acreage (1)(2)		Undeveloped Acreage (1)(3)
	Gross (4)	Net (5)	Gross (4)	Net (5)
Onshore Arkansas	3,636	2,545	41,664	29,165
Onshore Alabama, Louisiana and Texas	140	98	6,090	4,263
Offshore Gulf of Mexico	15,000	4,297	264,127	141,030
Total	18,776	6,940	311,881	174,458

(1) Excludes any interest in acreage in which we have no working interest before payout or before initial production.

(2) Developed acreage consists of acres spaced or assignable to productive wells.

(3) Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

(4) Gross acres refer to the number of acres in which we own a working interest.

(5) Net acres represent the number of acres attributable to an owner’s proportionate working interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is equivalent to 160 net acres).

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Included in the Offshore Gulf of Mexico acres shown in the table above are the beneficial interests Contango has in the offshore acreage owned by its partially owned subsidiaries. The above table includes (i) our 42.7% interest in Republic Exploration LLC’s 2,844 net developed acres and 122,376 net undeveloped acres, (ii) our 76.0% interest in Contango Offshore Exploration LLC’s 3,000 net developed acres and 92,131 net undeveloped acres, and (iii) our 50% interest in Magnolia Offshore Exploration LLC’s 1,920 net undeveloped acres. In addition, the Company holds royalty interests in approximately 36,441 gross undeveloped acres (1,179 net undeveloped acres) and 9,651 gross developed acres (227 net developed acres), offshore in the Gulf of Mexico.

Productive Wells

The following table sets forth the number of gross and net productive natural gas and oil wells in which we owned an interest as of June 30, 2007:

	Total Productive Wells (1)
	Gross (2)	Net (3)
Natural gas (onshore)	85	11.5
Natural gas (offshore)	8	2.0
Oil	-	-
Total	93	13.5

(1) Productive wells are producing wells and wells capable of producing commercial quantities. Completed but marginally producing wells are not considered here as a “productive” well.

(2) A gross well is a well in which we own an interest.

(3) The number of net wells is the sum of our fractional working interests owned in gross wells.

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Natural Gas and Oil Reserves

The following table presents our estimated net proved natural gas and oil reserves and the pre-tax net present value of our reserves at June 30, 2007, based on a reserve reports generated by William M. Cobb & Associates, Inc. and W.D. Von Gonten & Co. The pre-tax net present value, discounted at 10%, is not intended to represent the current market value of the estimated natural gas and oil reserves we own.

The pre-tax net present value of future cash flows attributable to our proved reserves prepared in accordance with SEC guidelines as of June 30, 2007 was based on $6.80 per million British thermal units (“MMbtu”) for natural gas at the NYMEX and $70.68 per barrel of oil at the West Texas Intermediate Posting, in each case before adjusting for basis, transportation costs and British thermal unit (“Btu”) content. For further information concerning the present value of future net cash flows from these proved reserves, see “Supplemental Oil and Gas Disclosures”.

	Total Proved Reserves as of June 30, 2007
	Producing		Non-Producing		Behind Pipe		Undeveloped		Total
Onshore
Natural gas (MMcf)		7,677		4,268		129		3,315	15,389
Oil and condensate (MBbls)		2		-		4		-	6
Total proved reserves (MMcfe)		7,689		4,268		153		3,315	15,425
Pre-tax net present value ($000) (Disc. @ 10%)	$	21,215	$	10,635	$	923	$	3,372	36,145
Offshore
Natural gas (MMcf)		17,625		27,963		59		16,856	62,503
Oil and condensate (MBbls)		344		475		2		337	1,158
Total proved reserves (MMcfe)		19,689		30,813		71		18,878	69,451
Pre-tax net present value ($000) (Disc. @ 10%)	$	97,322	$	139,874	$	387	$	55,451	293,034
Total
Natural gas (MMcf)		25,302		32,231		188		20,171	77,892
Oil and condensate (MBbls)		346		475		6		337	1,164
Total proved reserves (MMcfe)		27,378		35,081		224		22,193	84,876
Pre-tax net present value ($000) (Disc. @ 10%)	$	118,537	$	150,509	$	1,310	$	58,823	329,179

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

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

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Item 3.  Legal Proceedings

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

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

During the quarter ended June 30, 2007, no matters were submitted to a vote of security holders.

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

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

	High		Low
Fiscal Year 2006:
Quarter ended September 30, 2005	$	12.10	$	9.52
Quarter ended December 31, 2005	$	13.82	$	9.87
Quarter ended March 31, 2006	$	13.58	$	11.40
Quarter ended June 30, 2006	$	14.14	$	11.85
Fiscal Year 2007:
Quarter ended September 30, 2006	$	14.45	$	11.47
Quarter ended December 31, 2006	$	24.09	$	10.46
Quarter ended March 31, 2007	$	22.49	$	19.74
Quarter ended June 30, 2007	$	39.35	$	21.38

On August 31, 2007, the closing price of our common stock on the American Stock Exchange was $36.60 per share, and there were approximately 16 million shares of Contango common stock outstanding, held by approximately 120 holders of record.

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

On July 15, 2005, we sold $10.0 million of our Series D preferred stock to a group of private investors. The Series D preferred stock was perpetual and cumulative, was senior to our common stock and was convertible at any time into shares of our common stock at a price of $12.00 per share. The dividend on the Series D preferred stock was paid quarterly in cash at a rate of 6.0% per annum or could be paid-in-kind at a rate of 7.5% per annum. Our registration statement filed with the Securities and Exchange Commission, covering the 833,330 shares of common stock issuable upon conversion of the Series D preferred stock, became effective on October 26, 2005.

In November 2006, two Series D preferred stockholders voluntarily elected to convert a total of 100 shares of Series D preferred stock to 41,666 shares of our common stock. The converted shares of Series D preferred stock had a face value of $0.5 million.

On January 15, 2007, we exercised our mandatory conversion rights pursuant to the terms of our Series D preferred stock, and converted all of the remaining 1,900 shares of our Series D preferred stock issued and outstanding into 791,664 shares of our common stock. The outstanding shares of the Series D preferred stock had a face value of $9.5 million.

On May 17, 2007, we sold $30.0 million of our Series E preferred stock to a group of private investors. The sale of the Series E preferred stock was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder, as a transaction not involving a public offering. The Series E preferred stock is perpetual and cumulative, is senior to our common stock and is convertible at any time by the holder into shares of our common stock at a price of $38.00 per share. The dividend on the Series E preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per

30

annum. We used the net proceeds to repay $15.0 million in debt outstanding from the Company’s $30.0 million term loan agreement and to fund the Company’s offshore Gulf of Mexico deep shelf exploration program and our Arkansas Fayetteville Shale play. We have filed a registration statement with the Securities and Exchange Commission, covering the 789,468 shares of common stock issuable upon conversion of the Series E preferred stock, which became effective on September 12, 2007.

The following table sets forth information about our equity compensation plan at June 30, 2007:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans
1999 Stock Incentive Plan	1,026,000	$	10.87	1,037,333

No equity securities of the Company were repurchased during the fiscal year ended June 30, 2007. We do not have a publicly announced program to repurchase shares of our common stock.

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The following graph compares the yearly percentage change from June 30, 2002 until June 30, 2007 in the cumulative total stockholder return on our common stock to the cumulative total return on the Russell 2000 Stock Index and a peer group of five independent oil and gas exploration companies selected by us. The companies in our selected peer group are Brigham Exploration Company, Carrizo Oil & Gas, Inc., Edge Petroleum Corp., Goodrich Petroleum Corp. and PetroQuest Energy, Inc. Our common stock began trading on the American Stock Exchange on January 19, 2001 and previously traded on the Nasdaq over-the-counter Bulletin Board. The graph assumes that a $100 investment was made in our common stock and each index on June 30, 2002 and that all dividends were reinvested. The stock performance for our common stock is not necessarily indicative of future performance.

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Item 6.  Selected Financial Data

	Year Ended June 30,
	2007			2006			2005			2004			2003
Financial Data:		(Dollar amounts in 000s, except per share amounts)
Revenues:
Natural gas and oil sales	$	18,688		$	920		$	1,089		$	107		$	228
Gain (loss) from hedging activities		-			-			-			58			(5,709	)
Total revenues	$	18,688		$	920		$	1,089		$	165		$	(5,481	)
Income (loss) from continuing operations	$	(2,694	)	$	(7,726	)	$	(5,147	)	$	(1,564	)	$	(13,452	)
Discontinued operations, net of income taxes		-			7,519			17,565			9,264			9,116
Net income (loss)	$	(2,694	)	$	(207	)	$	12,418		$	7,700		$	(4,336	)
Preferred stock dividends		540			601			420			620			600
Net income (loss) attributable to common stock	$	(3,234	)	$	(808	)	$	11,998		$	7,080		$	(4,936	)
Net income (loss) per share:
Basic
Continuing operations	$	(0.21	)	$	(0.56	)	$	(0.42	)	$	(0.20	)	$	(1.54	)
Discontinued operations		-			0.51			1.34			0.88			1.00
Total	$	(0.21	)	$	(0.05	)	$	0.92		$	0.68		$	(0.54	)
Diluted
Continuing operations	$	(0.21	)	$	(0.56	)	$	(0.42	)	$	(0.20	)	$	(1.54	)
Discontinued operations		-			0.51			1.34			0.88			1.00
Total	$	(0.21	)	$	(0.05	)	$	0.92		$	0.68		$	(0.54	)
Weighted average shares outstanding:
Basic		15,430			14,760			13,089			10,484			9,129
Diluted		15,430			14,760			13,089			10,484			9,129
Working capital (deficit)	$	(4,088	)	$	18,333		$	28,839		$	3,032		$	(1,676	)
Capital expenditures	$	78,997		$	34,879		$	9,677		$	12,384		$	22,769
Long term debt	$	20,000		$	10,000		$	-		$	7,089		$	16,460
Stockholders’ equity	$	90,804		$	62,540		$	50,979		$	36,117		$	20,738
Total assets	$	153,936		$	89,385		$	53,353		$	45,511		$	46,305
Proved Reserve Data:
Total proved reserves (Mmcfe)		84,876			3,430			1,373			17,422			23,592
Pre-tax net present value (SEC at 10%)	$	329,179		$	8,852		$	7,081		$	59,767		$	69,627

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PART II

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and the related notes and other information included elsewhere in this report.

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.

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The table below sets forth revenue and production data for continuing operations for the fiscal years ended June 30, 2007, 2006 and 2005.

	Year ended June 30,							Year ended June 30,
	2007			2006		%		2006		2005		%
Revenues:		($000)							($000)
Natural gas and oil sales	$	18,688		$	920	1931	%	$	920	$	1,089	-16	%
Total revenues	$	18,688		$	920			$	920	$	1,089
Production:
Natural gas (million cubic feet)		2,452			91	2595	%		91		71	28	%
Oil, condensate and NGLs (thousand barrels)		39			4	875	%		4		8	-50	%
Total (million cubic feet equivalent)		2,686			115	2236	%		115		119	-3	%
Natural gas (thousand cubic feet per day)		6,718			249	2595	%		249		195	28	%
Oil, condensate and NGLs (barrels per day)		107			11	875	%		11		22	-50	%
Total (thousand cubic feet per day equivalent)		7,360			315	2236	%		315		327	-4	%
Average Sales Price:
Natural gas (per thousand cubic feet)	$	6.68		$	7.15	-7	%	$	7.15	$	8.40	-15	%
Oil, condensate and NGLs (per barrel)	$	59.67		$	61.53	-3	%	$	61.53	$	58.93	4	%
Operating expenses	$	1,672		$	13	12762	%	$	13	$	20	-35	%
Exploration expenses	$	6,782		$	8,202	-17	%	$	8,202	$	5,870	40	%
Depreciation, depletion and amortization	$	3,267		$	233	1302	%	$	233	$	352	-34	%
Impairment of natural gas and oil properties	$	192		$	708	-73	%	$	708	$	237	199	%
General and administrative expenses	$	6,842		$	4,761	44	%	$	4,761	$	3,571	33	%
Interest expense, net of interest capitalized	$	2,163		$	54	3906	%	$	54	$	72	-25	%
Interest income	$	886		$	826	7	%	$	826	$	432	91	%
Gain (loss) on sale of assets and other	$	(2,684	)	$	250	-1174	%	$	250	$	705	-65	%

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.

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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,

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General and administrative expenses for the year ended June 30, 2006 were approximately $4.8 million, up from $3.6 million for the year ended June 30, 2005. Major components of general and administrative expenses for the year ended June 30, 2006 included approximately $1.8 million in salaries, benefits and bonuses, $0.9 million in office administration and other expenses, $0.3 million in insurance costs, $0.5 million in accounting and tax services, $0.4 million in legal and other administrative expenses, and $0.9 million in non-cash expenses related to the cost of expensing stock options.

General and administrative expenses for the year ended June 30, 2005 were approximately $3.6 million. Major components of general and administrative expenses for the year ended June 30, 2005 included approximately $1.3 million in salaries, benefits and bonuses, $1.2 million in office administration and other expenses, $0.3 million in insurance costs, $0.4 million in legal and other professional fees and other administrative expenses, and $0.4 million in non-cash expenses related to the cost of expensing stock options.

Interest Expense.  Interest expense for the fiscal years ended June 30, 2007, 2006 and 2005 were approximately $2.2 million, $54,488 and $71,506, respectively. The higher level of interest expense for fiscal year 2007 was attributable to a higher levels of bank debt outstanding during such period. The lower levels of interest expense in fiscal years 2006 and 2005 were attributable to the Company retiring all of its long term debt in the second quarter of fiscal year 2005. Interest of approximately $1.1 million was capitalized for unevaluated property for the fiscal year ended June 30, 2007.

Interest Income.  Interest income for the fiscal years ended June 30, 2007, 2006 and 2005 were approximately $0.9 million, $0.8 million and $0.4 million, respectively. The higher levels of interest income for fiscal years 2007 and 2006 were attributable to loans made to affiliates and interest earned on the proceeds from the sale of our south Texas natural gas and oil interests to Edge Petroleum in December 2004 plus interest earned on the proceeds from property sales effective February 1, 2006 and April 1, 2006.

Gain on Sale of Assets and Other.  We reported a loss on sale of assets and other of approximately $2.7 million for the year ended June 30, 2007, which consists of a $2.3 million loss on COI’s sale of Grand Isle 72 and a $0.4 million loss on equity investments.

We reported a gain on sale of assets and other of approximately $0.3 million for the year ended June 30, 2006, which represents other income recognized by our partially-owned subsidiary, COE.

We reported gain on sale of assets and other of approximately $0.7 million for the year ended June 30, 2005, which represents a $0.8 million unrealized gain recorded as a result of a mark-to-market increase in the value of our alternative energy investments, offset by approximately $0.1 million in operating losses related to our alternative energy investments.

Discontinued Operations.  The Company had no discontinued operations for the fiscal year ended June 30, 2007. The table and discussions above, along with our financial statements, discuss only continuing operations for all fiscal years presented. Not reflected are the Company’s sold producing properties which generated 84.1% and 93.3% of combined revenues for the fiscal years ended June 30, 2006 and 2005, respectively. Please see Note 6 – Sale of Properties – Discontinued Operations of Notes to Consolidated Financial Statements included as part of this Form 10-K, for a discussion of our discontinued operations.

Capital Resources and Liquidity

The Company, since its inception in September 1999, has raised $87.0 million in proceeds from eight separate property sales, and views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, in addition to being a source of funds for potentially higher rate of return natural gas and oil exploration investments. We believe these periodic natural gas and oil property sales are an efficient strategy to meet our cash and liquidity needs by providing us with immediate cash, which would otherwise take years to realize through the production lives of the fields sold. We have in the past and expect to in the future to continue to rely heavily on the sales of assets to generate cash to fund our exploration investments and operations.

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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.

Fiscal Year of Property Sale	Proceeds Received		Reserves Sold (Mmcfe)	Reserves at end of Fiscal Year (Mmcfe)	Standardized Measure of Discounted Future Net Cash Flows at end of Fiscal Year
2005	$	40,131,428	16,015	1,373	$	5,250,600
2006	$	12,892,916	2,294	3,430	$	7,734,106
2007	$	7,000,000	426	84,876	$	252,297,275

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

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$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.

Off Balance Sheet Arrangements

None.

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Contractual Obligations

The following table summarizes our known contractual obligations as of June 30, 2007:

	Payment due by period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long term debt	$	20,000,000	$	-	$	20,000,000		-	$	-
Operating leases		572,877		134,115		394,850		43,912		-
Total	$	20,572,877	$	134,115	$	20,394,850	$	43,912	$	-

Additionally, once we have completed drilling Mary Rose #1, should we choose not to retain the drilling rig, we are committed to pay a dayrate equal to $48,000 per day (approximately $7,500 per day, net to COI and $26,700 per day, net to REX) for 53 days, or until the rig is hired by another company, whichever occurs first. The Company is also building a production platform and 20 inch, 20 mile pipeline at Eugene Island 11 at an estimated 8/8ths cost of $56.0 million (approximately $8.8 million net to COI and $31.2 million net to REX). As of August 31, 2007, the Company was committed to approximately $6.0 million of this cost ($0.9 million net to COI and $3.3 million net to REX).

Long-Term Debt

The Company has $20.0 million outstanding under a three-year $20.0 million secured term loan facility (the “RBS Facility”) with The Royal Bank of Scotland plc (“RBS”). The RBS Facility is secured with the stock of Sundance. Sundance owns a 10% limited partnership interest in Freeport LNG, which owns the Freeport LNG facility. Borrowings under the RBS Facility bear interest, at the Company’s option, at either (i) 30 day LIBOR, (ii) 60 day LIBOR, (iii) 90 day LIBOR or (iv) 6 month LIBOR, all plus 6.5%. Interest is due at the end of the LIBOR period chosen. The average interest rate charged for the fiscal year ended June 30, 2007 was 11.91%. The principal is due April 27, 2009, but we may prepay after April 27, 2008 with no prepayment penalty.

On January 30, 2007, the Company completed the arrangement of a $30.0 million secured term loan agreement with a private investment firm (the “Term Loan Agreement”). The Term Loan Agreement is secured with substantially all the assets of the Company, except for the stock of Sundance, which is pledged to RBS under our RBS Facility. As of August 31, 2007, the Company had no amounts outstanding under the Term Loan Agreement. Borrowings bear interest at 30 day LIBOR plus 5.0%. The average interest rate charged for the fiscal year ended June 30, 2007 was 10.32%. Accrued interest is due monthly. The principal is due December 31, 2008, but we may prepay at any time with no prepayment penalty. An arrangement fee of 1%, or $300,000, was paid in connection with the term loan. Additionally, we pay a non-use fee in the amount of 1.50% per annum multiplied by such non-funded amount.

Both the Term Loan Agreement and the RBS Facility require a minimum level of working capital and contain certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required working capital or comply with certain covenants in the Term Loan Agreement and RBS Facility could result in a default and acceleration of all indebtedness under such credit facilities. As of June 30, 2007, the Company was in compliance with its financial covenants, ratios and other provisions of the Term Loan Agreement and RBS Facility.

Application of Critical Accounting Policies and Management’s Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. The Company’s significant accounting policies are described in Note 2 of Notes to Consolidated Financial Statements included as part of this Form 10-K. We have identified below the policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. The Company analyzes its estimates, including those related to oil and gas reserve

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estimates, on a periodic basis and bases its estimates on historical experience, independent third party reservoir engineers and various other assumptions that management believes to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of the Company’s financial statements:

Successful Efforts Method of Accounting.  Our application of the successful efforts method of accounting for our oil and gas business activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil and gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of oil and gas leasehold acquisition costs included in unproved properties requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Reserve Estimates.  The Company’s estimates of oil and gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and/or the rate of depletion of such oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material. Holding all other factors constant, a reduction in the Company’s proved reserve estimate at June 30, 2007 of 1% would not have a material effect on depreciation, depletion and amortization expense.

Impairment of Oil and Gas Properties.  The Company reviews its proved oil and gas properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. The Company compares expected undiscounted future net cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted net cash flows, based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require the Company to record an

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impairment of its oil and gas properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.

Stock-Based Compensation.  Effective July 1, 2006, we adopted Statement No. 123(R) (revised 2004) (“SFAS 123(R)”), “Share-Based Payment”, which requires companies to measure and recognize compensation expense for all stock-based payments at fair value. SFAS 123(R) requires that management make assumptions including stock price volatility and employee turnover that are utilized to measure compensation expense. The fair value of stock options granted is estimated at the date of grant using the Black-Scholes option-pricing model. This model requires the input of highly subjective assumptions, which are set forth in Note 2 of Notes to Consolidated Financial Statements included as part of this Form 10-K.

Recent Accounting Pronouncements

In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159 (“SFAS 159”), “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred. SFAS 159 becomes effective as of the beginning of the first fiscal year that begins after November 15, 2007, with early adoption permitted. However, entities may not retroactively apply the provisions of SFAS 159 to fiscal years preceding the date of adoption. We are currently evaluating the impact that SFAS 159 may have on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157 (“SFAS 157”), “Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value under Generally Accepted Accounting Principles and requires enhanced disclosures about fair value measurements. It does not require any new fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We are currently evaluating the impact SFAS 157 will have on the Company.

In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 and assessing the impact, if any, it may have on our financial position, results of operations or cash flows.

Item 7A.  Quantitative and Qualitative Disclosure about Market Risk

Commodity Risk.  Our major commodity price risk exposure is to the prices received for our natural gas and oil production. Realized commodity prices received for our production are tied to the spot prices applicable to natural gas and crude oil at the applicable delivery points. Prices received for natural gas and oil are volatile, unpredictable and are beyond our control. For the year ended June 30, 2007, a 10% fluctuation in the prices received for natural gas and oil production would have had an approximate $1.9 million impact on our revenues.

Interest Rate Risk.  We have long-term debt subject to the risk of loss associated with movements in interest rates. As of August 31, 2007, we had $20.0 million of variable rate long-term debt outstanding due in April 2009. This variable rate obligation exposes us to the risk of increased interest expense in the event of increases in short-term interest rates. The impact on annual cash flow of a 10% change in the floating rate applicable to our variable rate debt would be approximately $150,000.

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Item 8.  Financial Statements and Supplementary Data

The financial statements and supplemental information required to be filed under Item 8 of Form 10-K are presented on pages F-1 through F-31 of this Form 10-K.

Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of the Company’s senior management of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Security Exchange Act of 1934 (the “Exchange Act”)) as of June 30, 2007, the end of the period covered by this report. Based on that evaluation, the Company’s management, including the Chairman, Chief Executive Officer, Chief Financial Officer, Controller and Treasurer, concluded that the Company’s disclosure controls and procedures were effective as of such date to ensure that information required to be disclosed in the reports that the Company files under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms, and (ii) would be accumulated and communicated to the Company’s management, including the Chairman, Chief Executive Officer and Chief Financial Officer, together with our Controller and Treasurer, as appropriate, to allow timely decisions regarding required disclosures.

Management’s Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of the Company’s management, including the Chairman, Chief Executive Officer and Chief Financial Officer, together with our Controller and the Treasurer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company’s evaluation under the framework in Internal Control—Integrated Framework, the Company’s management concluded that its internal control over financial reporting was effective as of June 30, 2007.

Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report on Form 10-K, has audited the effectiveness of our internal control over financial reporting as of June 30, 2007, as stated in their report which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and

Shareholders of Contango Oil & Gas Company

We have audited Contango Oil & Gas Company (a Delaware Corporation) and subsidiaries’ internal control over financial reporting as of June 30, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Contango Oil & Gas Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on Contango Oil & Gas Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Contango Oil & Gas Company and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of June 30, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Contango Oil & Gas Company and subsidiaries as of June 30, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended June 30, 2007 and our report dated September 11, 2007 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Houston, Texas

September 11, 2007

44

Changes in Internal Control Over Financial Reporting

There was no change in our internal controls over financial reporting during the period covered by this annual report on Form 10-K that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information

None.

PART III

Item 10.  Directors, Executive Officers and Corporate Governance

The information regarding directors, executive officers, promoters and control persons required under Item 10 of Form 10-K will be contained in our Definitive Proxy Statement for our 2006 Annual Meeting of Stockholders (the “Proxy Statement”) under the headings “Election of Directors”, “Executive Compensation”, “Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance” and is incorporated herein by reference. The Proxy Statement will be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Exchange Act of 1934, as amended, not later than 120 days after June 30, 2007.

Item 11.  Executive Compensation

The information required under Item 11 of Form 10-K will be contained in the Proxy Statement under the heading “Executive Compensation” and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder     Matters

The information required under Item 12 of Form 10-K will be contained in the Proxy Statement under the heading “Security Ownership of Certain Other Beneficial Owners and Management” and is incorporated herein by reference.

Item 13.  Certain Relationships and Related Transactions, and Director Independence

The information required under Item 13 of Form 10-K will be contained in the Proxy Statement under the heading “Certain Relationships and Related Transactions, and Director Independence” and “Executive Compensation” and is incorporated herein by reference.

Item 14.  Principal Accountant Fees and Services

The information required under Item 14 of Form 10-K will be contained in the Proxy Statement under the heading “Principal Accountant Fees ands Services” and is incorporated herein by reference.

PART IV

Item 15.  Exhibits and Financial Statement Schedules

(a) Financial Statements and Schedules:

The financial statements are set forth in pages F-1 to F-30 of this Form 10-K. Financial statement schedules have been omitted since they are either not required, not applicable, or the information is otherwise included.

45

(b) Exhibits:

The following is a list of exhibits filed as part of this Form 10-K. Where so indicated by a footnote, exhibits, which were previously filed, are incorporated herein by reference.

Exhibit Number	Description
2.1	Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and REX Offshore Corporation, dated as of September 1, 2005. (17)
2.2	Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and COE Offshore, LLC dated as of September 1, 2005. (17)
2.3	Purchase and Sale Agreement between Contango STEP, LP and Rosetta Resources Operating LP, dated April 28, 2006. (19)
2.4	Purchase and Sale Agreement between Contango Operators, Inc. and Rosetta Resources Offshore LLC, dated December 14, 2006. (21)
3.1	Certificate of Incorporation of Contango Oil & Gas Company. (6)
3.2	Bylaws of Contango Oil & Gas Company. (6)
3.3	Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation. (6)
3.4	Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (11)
4.1	Facsimile of common stock certificate of Contango Oil & Gas Company. (1)
4.2	Certificate of Designations, Preferences and Relative Rights and Limitations for Series C Senior Convertible Cumulative Preferred Stock of Contango Oil & Gas Company. (13)
4.3	Certificate of Designations, Preferences and Relative Rights and Limitations for Series D Perpetual Cumulative Convertible Preferred Stock of Contango Oil & Gas Company. (16)
4.4	Securities Purchase Agreement, dated as of July 15, 2005, among Contango Oil & Gas Company and the Purchasers Named Therein, relating to the Series D Perpetual Cumulative Convertible Preferred Stock. (16)
4.5	Certificate of Designations, Preferences and Relative Rights and Limitations for Series E Perpetual
	Cumulative Convertible Preferred Stock of Contango Oil & Gas Company. (22)
4.6	Securities Purchase Agreement, dated as of May 11, 2007, among Contango Oil & Gas Company and the Purchasers Named Therein, relating to the Series E Perpetual Cumulative Convertible Preferred Stock. (22)
10.1	Agreement, dated effective as of September 1, 1999, between Contango Oil & Gas Company and Juneau Exploration, L.L.C. (2)
10.2	Securities Purchase Agreement between Contango Oil & Gas Company and Trust Company of the West, dated December 29, 1999. (9)
10.3	Warrant to Purchase Common Stock between Contango Oil & Gas Company and Trust Company of the West, dated December 29, 1999. (3)
10.4	Co-Sale Agreement among Kenneth R. Peak, Contango Oil & Gas Company and Trust Company of the West, dated December 29, 1999. (3)
10.5	Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Trust Company of the West. (4)
10.6	Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Fairfield Industries Incorporated. (4)
10.7	Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Juneau Exploration Company, L.L.C. (4)

46

10.8	Amendment dated August 14, 2000 to agreement between Contango Oil & Gas Company and Juneau Exploration Company, LLC. dated effective as of September 1, 1999. (5)
10.9	Asset Purchase Agreement by and among Juneau Exploration, L.P. and Contango Oil & Gas Company dated January 4, 2002. (7)
10.10	Asset Purchase Agreement by and among Mark A. Stephens, John Miller, The Hunter Revocable Trust, Linda G. Ferszt, Scott Archer and the Archer Revocable Trust and Contango Oil & Gas Company dated January 9, 2002. (8)
10.11	Option Purchase Agreement between Contango Oil & Gas Company and Cheniere Energy, Inc. dated June 4, 2002. (10)
10.12	Securities Purchase Agreement dated December 12, 2003 by and between Contango Oil & Gas Company and the Purchasers Named Therein. (13)
10.13	Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated February 27, 2003. (14)
10.14	Partnership Purchase Agreement among Contango Sundance, Inc., Contango Oil & Gas, Cheniere LNG, Inc. and Cheniere Energy, Inc. dated March 1, 2003. (14)
10.15	First Amendment, dated December 19, 2003, to Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated February 27, 2003. (14)
10.16	Asset Purchase Agreement, dated as of October 7, 2004, by and between Contango Oil & Gas Company; Contango STEP, L.P.; Edge Petroleum Exploration Company; and Edge Petroleum Corporation. (15)
10.17	Limited Liability Company Agreement of Republic Exploration LLC dated August 24, 2000. (17)
10.18	Amendment to Limited Liability Company Agreement and Additional Agreements of Republic Exploration LLC dated as of September 1, 2005. (17)
10.19	Limited Liability Company Agreement of Contango Offshore Exploration LLC dated November 1, 2000. (17)
10.20	First Amendment to Limited Liability Company Agreement and Additional Agreements of Contango Offshore Exploration LLC dated as of September 1, 2005. (17)
10.21*	Contango Oil & Gas Company 1999 Stock Incentive Plan. (18)
10.22*	Amendment No. 1 to Contango Oil & Gas Company 1999 Stock Incentive Plan dated as of March 1, 2001. (18)
10.23	Term Loan Agreement between Contango Oil & Gas Company and The Royal Bank of Scotland plc, dated April 27, 2006. (20)
10.24	Demand Promissory Note dated October 26, 2006 with Schedules I, II and III. (23)
10.25	Term Loan Agreement between Contango Oil & Gas Company and Centaurus Capital LLC, dated January 30, 2007. (24)
10.26	Form of Pledge Agreement. (24)
14.1	Code of Ethics. (12)
21.1	List of Subsidiaries. †
21.2	Organizational Chart. †
23.1	Consent of W.D. Von Gonten & Co. †
23.2	Consent of William M. Cobb & Associates, Inc. †
23.3	Consent of Grant Thornton LLP. †
31.1	Certification required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. †
32.1	Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. †

47

† Filed herewith.

* Indicates a management contract or compensatory plan or arrangement.

1. Filed as an exhibit to the Company’s Form 10-SB Registration Statement, as filed with the Securities and Exchange Commission on October 16, 1998.

2. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on November 11, 1999.

3. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on February 14, 2000.

4. Filed as an exhibit to the Company’s report on Form 8-K, dated August 24, 2000, as filed with the Securities and Exchange Commission of September 8, 2000.

5. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2000, as filed with the Securities and Exchange Commission on September 27, 2000.

6. Filed as an exhibit to the Company’s report on Form 8-K, dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000.

7. Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2002, as filed with the Securities and Exchange Commission on January 8, 2002.

8. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended March 31, 2002, as filed with the Securities and Exchange Commission on February 14, 2002.

9. Filed as an exhibit to the Company’s report on Form 10-QSB/A for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on June 4, 2002.

10. Filed as an exhibit to the Company’s Registration Statement on Form S-1 (Registration No. 333-89900) as filed with the Securities and Exchange Commission on June 14, 2002.

11. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 2002, dated November 14, 2002, as filed with the Securities and Exchange Commission.

12. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2003, as filed with the Securities and Exchange Commission on September 22, 2003.

13. Filed as an exhibit to the Company’s report on Form 8-K, dated December 12, 2003, as filed with the Securities and Exchange Commission on December 17, 2003.

14. Filed as an exhibit to the Company’s report on Form 8-K, dated December 19, 2003, as filed with the Securities and Exchange Commission on December 23, 2003.

15. Filed as an exhibit to the Company’s report on Form 8-K, dated September 27, 2004, as filed with the Securities and Exchange Commission on October 8, 2004.

16. Filed as an exhibit to the Company’s Registration Statement filed on Form S-3 as filed with the Securities and Exchange Commission on August 2, 2005.

17. Filed as an exhibit to the Company’s report on Form 8-K, dated September 2, 2005, as filed with the Securities and Exchange Commission on September 8, 2005.

18. Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2005, as filed with the Securities and Exchange Commission on September 13, 2005.

19. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2006, dated May 15, 2006, as filed with the Securities and Exchange Commission.

20. Filed as Exhibit 10.1 to the Company’s report on Form 10-Q for the quarter ended March 31, 2006, dated May 15, 2006, as filed with the Securities and Exchange Commission.

21. Filed as an exhibit to the Company’s report on Form 8-K, dated December 14, 2006, as filed with the Securities and Exchange Commission on December 20, 2006.

22. Filed as an exhibit to the Company’s report on Form 8-K, dated May 11, 2007, as filed with the Securities and Exchange Commission on May 17, 2007.

23. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2006, dated November 8, 2006, as filed with the Securities and Exchange Commission.

24. Filed as an exhibit to the Company’s report on Form 8-K, dated January 30, 2007, as filed with the Securities and Exchange Commission on February 5, 2007.

48

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CONTANGO OIL & GAS COMPANY
/s/ KENNETH R. PEAK	/s/ LESIA BAUTINA
Kenneth R. Peak	Lesia Bautina
Chairman, Chief Executive Officer and Chief Financial Officer (principal executive officer and principal financial officer)	Senior Vice President and Controller (principal accounting officer)

49

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Title	Date
/s/ KENNETH R. PEAK	Chairman of the Board	September 13, 2007
Kenneth R. Peak
/s/ B.A. BERILGEN	Director	September 13, 2007
B.A. Berilgen
/s/ JAY D. BREHMER	Director	September 13, 2007
Jay D. Brehmer
/s/ CHARLES M. REIMER	Director	September 13, 2007
Charles M. Reimer
/s/ STEVEN L. SCHOONOVER	Director	September 13, 2007
Steven L. Schoonover
/s/ DARRELL W. WILLIAMS	Director	September 13, 2007
Darrell W. Williams

50

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets, June 30, 2007 and 2006	F-3
Consolidated Statements of Operations for the Years Ended June 30, 2007, 2006 and 2005	F-5
Consolidated Statements of Cash Flows for the Years Ended June 30, 2007, 2006 and 2005	F-6
Consolidated Statements of Shareholders’ Equity for the Years Ended June 30, 2007, 2006 and 2005	F-7
Notes to Consolidated Financial Statements	F-8
Supplemental Oil and Gas Disclosures (Unaudited)	F-26
Quarterly Results of Operations (Unaudited)	F-30

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Contango Oil & Gas Company

We have audited the accompanying consolidated balance sheets of Contango Oil & Gas Company (a Delaware corporation) and subsidiaries as of June 30, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended June 30, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Contango Oil & Gas Company and subsidiaries as of June 30, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2007 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Contango Oil & Gas Company and subsidiaries’ internal control over financial reporting as of June 30, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated September 11, 2007 expressed an unqualified opinion on the effectiveness of internal control over financial reporting.

GRANT THORNTON LLP

Houston, Texas

September 11, 2007

F-2

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

	June 30,
	2007			2006
CURRENT ASSETS:
Cash and cash equivalents	$	6,177,618		$	10,274,950
Short-term investments		2,200,576			18,472,327
Inventory tubulars		334,797			194,825
Accounts receivable:
Trade receivable		7,853,080			481,593
Advances to affiliates		5,259,191			256,180
Joint interest billings receivable		7,894,505			3,422,261
Prepaid capital costs		5,539,419			1,208,299
Income tax receivable		2,666,884			100,000
Other		255,788			102,583
Total current assets		38,181,858			34,513,018
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		82,655,848			18,395,015
Unproved properties		22,012,054			23,293,300
Furniture and equipment		235,512			231,877
Accumulated depreciation, depletion and amortization		(3,584,618	)		(662,877	)
Total property, plant and equipment, net		101,318,796			41,257,315
OTHER ASSETS:
Cash and other assets held by affiliates		1,195,074			1,054,100
Investment in Freeport LNG Project		3,243,585			3,243,585
Investment in Contango Venture Capital Corporation		5,864,558			4,453,028
Deferred income tax asset		3,377,016			4,455,190
Facility fees and other assets		754,622			408,769
Total other assets		14,434,855			13,614,672
TOTAL ASSETS	$	153,935,509		$	89,385,005

The accompanying notes are an integral part of these consolidated financial statements.

F-3

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

	June 30,
	2007			2006
CURRENT LIABILITIES:
Accounts payable	$	14,659,860		$	1,041,505
Joint interest advances		-			5,638,600
Accrued exploration and development		14,235,062			8,278,245
Advances from affiliates		3,417,103			194,862
Debt of affiliates		8,540,091			-
Other accrued liabilities		1,417,279			1,026,743
Total current liabilities		42,269,395			16,179,955
LONG-TERM DEBT		20,000,000			10,000,000
ASSET RETIREMENT OBLIGATION		862,344			665,458
COMMITMENTS AND CONTINGENCIES (NOTE 15)
SHAREHOLDERS’ EQUITY:
Convertible preferred stock, 6%, Series E, $0.04 par value, 10,000 shares authorized, 6,000 shares issued and outstanding at June 30, 2007, liquidation preference of $30,000,000 at $5,000 per share		240			-
Convertible preferred stock, 6%, Series D, $0.04 par value, 4,000 shares authorized, 2,000 shares issued and outstanding at June 30, 2006, liquidation preference of $10,000,000 at $5,000 per share		-			80
Common stock, $0.04 par value, 50,000,000 shares authorized, 18,539,807 shares issued and 15,964,807 outstanding at June 30, 2007, 17,574,085 shares issued and 14,999,085 outstanding at June 30, 2006,		741,591			702,961
Additional paid-in capital		75,849,506			45,105,504
Accumulated other comprehensive income		715,659			-
Treasury stock at cost (2,575,000 shares)		(6,180,000	)		(6,180,000	)
Retained earnings		19,676,774			22,911,047
Total shareholders’ equity		90,803,770			62,539,592
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	153,935,509		$	89,385,005

The accompanying notes are an integral part of these consolidated financial statements.

F-4

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended June 30,
	2007			2006			2005
REVENUES:
Natural gas and oil sales	$	18,687,821		$	920,304		$	1,088,933
Total revenues		18,687,821			920,304			1,088,933
EXPENSES:
Operating expenses		1,671,824			13,350			19,683
Exploration expenses		6,782,425			8,202,385			5,870,066
Depreciation, depletion and amortization		3,267,252			232,702			352,114
Impairment of natural gas and oil properties		192,109			707,523			236,537
General and administrative expense		6,841,721			4,760,662			3,570,957
Total expenses		18,755,331			13,916,622			10,049,357
LOSS FROM CONTINUING OPERATIONS BEFORE OTHER INCOME AND INCOME TAXES		(67,510	)		(12,996,318	)		(8,960,424	)
OTHER INCOME (EXPENSE):
Interest expense (net of interest capitalized)		(2,162,573	)		(54,488	)		(71,506	)
Interest income		886,420			826,399			431,803
Gain (loss) on sale of assets and other		(2,684,062	)		249,611			705,147
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(4,027,725	)		(11,974,796	)		(7,894,980	)
Benefit from income taxes		1,333,174			4,248,623			2,748,121
LOSS FROM CONTINUING OPERATIONS		(2,694,551	)		(7,726,173	)		(5,146,859	)
DISCONTINUED OPERATIONS (Note 5)
Discontinued operations, net of income taxes		-			7,519,210			17,564,795
NET INCOME (LOSS)		(2,694,551	)		(206,963	)		12,417,936
Preferred stock dividends		539,722			601,000			420,000
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(3,234,273	)	$	(807,963	)	$	11,997,936
NET INCOME (LOSS) PER SHARE:
Basic
Continuing operations	$	(0.21	)	$	(0.56	)	$	(0.42	)
Discontinued operations		-			0.51			1.34
Total	$	(0.21	)	$	(0.05	)	$	0.92
Diluted
Continuing operations	$	(0.21	)	$	(0.56	)	$	(0.42	)
Discontinued operations		-			0.51			1.34
Total	$	(0.21	)	$	(0.05	)	$	0.92
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		15,430,146			14,760,268			13,089,332
Diluted		15,430,146			14,760,268			13,089,332

The accompanying notes are an integral part of these consolidated financial statements.

F-5

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended June 30,
	2007			2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Loss from continuing operations	$	(2,694,551	)	$	(7,726,173	)	$	(5,146,859	)
Plus income from discontinued operations, net of income taxes		-			7,519,210			17,564,795
Net income (loss)		(2,694,551	)		(206,963	)		12,417,936
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		3,267,252			1,199,436			2,815,982
Impairment of natural gas and oil properties		192,109			707,523			236,537
Exploration expenditures		5,473,218			8,221,045			4,875,506
Deferred income taxes		692,818			7,139			(3,273,922	)
Loss (gain) on sale of assets and other		2,313,334			(7,232,351	)		(16,993,441	)
Stock-based compensation		1,492,765			856,412			385,193
Tax benefit from exercise of stock options		(188,897	)		(359,772	)		591,226
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable and other		(7,599,816	)		947,586			3,341,701
Increase in notes receivable		(1,005,000	)		-			-
Increase in prepaid insurance		(205,904	)		(20,640	)		(10,498	)
Increase in inventory		(139,972	)		(194,825	)		-
Increase (decrease) in accounts payable and advances from joint owners		4,570,213			6,219,698			(165,032	)
Increase (decrease) in other accrued liabilities		(87,286	)		792,025			(731,004	)
(Decrease) increase in income taxes payable		(2,377,988	)		(1,398,776	)		1,417,790
Other		370,723			(64,921	)		550
Net cash provided by operating activities		4,073,018			9,472,616			4,908,524
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures		(77,547,111	)		(34,093,358	)		(7,630,280	)
Decrease (increase) in net investment in affiliates		(140,974	)		288,840			(287,902	)
Investment in Freeport LNG Project		-			(236,834	)		(673,418	)
Sale (purchase) of short-term investments, net		16,271,751			7,027,542			(25,499,869	)
Additions to furniture and equipment		(26,659	)		(20,425	)		(16,412	)
Decrease (increase) in advances to operators		-			1,137,056			(509,662	)
Investment in Contango Venture Capital Corporation		(681,244	)		(2,156,447	)		(1,023,668	)
Acquisition of overriding royalty interests		-			(1,000,000	)		-
Acquisition of Republic Exploration LLC and Contango Offshore Exploration LLC interests		-			(7,500,000	)		-
Sale/Acquisition costs		-			(7,170	)		(168,686	)
Proceeds from the sale of assets		7,000,000			12,892,916			40,131,428
Net cash provided by (used in) investing activities		(55,124,237	)		(23,667,880	)		4,321,531
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		25,000,000			10,000,000			2,200,000
Repayments under credit facility		(15,000,000	)		-			(9,289,000	)
Borrowings by affiliates		8,540,091			-			-
Proceeds from preferred equity issuances, net of issuance costs		28,783,936			9,616,438			-
Preferred stock dividends		(539,722	)		(601,000	)		(420,000	)
Repurchase/cancellation of stock options		(202,521	)		-			-
Proceeds from exercise of options and warrants		519,715			1,535,880			1,888,167
Tax benefit from exercise of stock options		188,897			359,772			-
Debt issue costs		(336,509	)		(426,651	)		(20,200	)
Net cash provided by (used in) financing activities		46,953,887			20,484,439			(5,641,033	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		(4,097,332	)		6,289,175			3,589,022
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		10,274,950			3,985,775			396,753
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	6,177,618		$	10,274,950		$	3,985,775
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes	$	451,993		$	1,045,816		$	7,974,387
Cash paid for interest	$	2,702,672		$	125,582		$	83,696

The accompanying notes are an integral part of these consolidated financial statements.

F-6

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

	Preferred Stock					Common Stock			Paid-in Capital			Accumulated Other Compre- hensive Income		Treasury Stock			Retained Earnings			Total Shareholders’ Equity			Compre- hensive Income
	Shares		Amount			Shares	Amount
Balance at June 30, 2004	1,600		$	64		12,310,700	$	595,428	$	29,979,965		$	-	$	(6,180,000	)	$	11,721,074		$	36,116,531
Exercise of stock options and warrants	-			-		747,584		29,902		1,858,265			-		-			-			1,888,167
Tax benefit from exercise of stock options	-			-		-		-		591,226			-		-			-			591,226
Cashless exercise of stock options and warrants	-			-		197,859		7,913		(7,913	)		-		-			-			-
Partial conversion of Series C preferred stock to common stock	(200	)		(8	)	166,666		6,667		(6,659	)		-		-			-			-
Expense of stock options	-			-		-		-		385,193			-		-			-			385,193
Net income	-			-		-		-		-			-		-			12,417,936			12,417,936
Preferred stock dividends	-			-		-		-		-			-		-			(420,000	)		(420,000	)
Comprehensive income	-			-		-		-		-			-		-			-			-		$	-
Balance at June 30, 2005	1,400		$	56		13,422,809	$	639,910	$	32,800,077			-	$	(6,180,000	)	$	23,719,010		$	50,979,053
Exercise of stock options and warrants	-			-		406,500		16,260		1,519,620			-		-			-			1,535,880
Tax benefit from exercise of stock options	-			-		-		-		359,772			-		-			-			359,772
Cashless exercise of stock options	-			-		3,114		125		(125	)		-		-			-			-
Conversion of Series C preferred stock to common stock	(1,400	)		(56	)	1,166,662		46,666		(46,610	)		-		-			-			-
Issuance of Series D preferred stock	2,000			80		-		-		9,616,358			-		-			-			9,616,438
Expense of stock options	-			-		-		-		856,412			-		-			-			856,412
Net loss	-			-		-		-		-			-		-			(206,963	)		(206,963	)
Preferred stock dividends	-			-		-		-		-			-		-			(601,000	)		(601,000	)
Comprehensive income	-			-		-		-		-			-		-			-			-		$	-
Balance at June 30, 2006	2,000		$	80		14,999,085	$	702,961	$	45,105,504		$	-	$	(6,180,000	)	$	22,911,047		$	62,539,592
Exercise of stock options	-			-		106,500		4,260		515,455			-		-			-			519,715
Tax benefit from exercise of stock options	-			-		-		-		155,003			-		-			-			155,003
Cancellation of stock options, net of tax benefit of $33,894	-			-		-		-		(168,627	)		-		-			-			(168,627	)
Cashless exercise of stock options	-			-		726		29		(29	)		-		-			-			-
Amortization of Restricted Stock	-			-		25,166		1,007		152,972			-		-			-			153,979
Conversion of Series D preferred stock to common stock	(2,000	)		(80	)	833,330		33,334		(33,254	)		-		-			-			-
Issuance of Series E preferred stock	6,000			240		-		-		28,783,696			-		-			-			28,783,936
Expense of stock options	-			-		-		-		1,338,786			-		-			-			1,338,786
Net loss	-			-		-		-		-			-		-			(2,694,551	)		(2,694,551	)		(2,694,551	)
Preferred stock dividends	-			-		-		-		-			-		-			(539,722	)		(539,722	)
Unrealized gain on available for sale securities, net of tax	-			-		-		-		-			715,659		-			-			715,659			715,659
Comprehensive income	-			-		-		-		-			-		-			-			-		$	(1,978,892	)
Balance at June 30, 2007	6,000		$	240		15,964,807	$	741,591	$	75,849,506		$	715,659	$	(6,180,000	)	$	19,676,774		$	90,803,770

The accompanying notes are an integral part of these consolidated financial statements.

F-7

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  Organization and Business

Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or “the Company”) 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”), a wholly-owned subsidiary, acts as operator on certain offshore prospects. The Company also owns a 10% interest in a limited partnership formed to develop a liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas, and holds investments in companies focused on commercializing environmentally preferred energy technologies.

2.  Summary of Significant Accounting Policies

The application of generally accepted accounting principles involves certain assumptions, judgments, choices and estimates that affect reported amounts of assets, liabilities, revenues and expenses. Thus, the application of these principles can result in varying results from company to company. Contango’s critical accounting principles, which are described below, relate to the successful efforts method for costs related to natural gas and oil activities, consolidation principles and stock based compensation, cash and cash equivalents, and short-term investments.

Use of Estimates.  The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make 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.

Revenue Recognition.  Revenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties. Revenues from natural gas production are recorded using the sales method. When sales volumes exceed the Company’s entitled share, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. At June 30, 2007 and 2006, the Company had no overproduced imbalances.

Cash Equivalents.  Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of June 30, 2007, the Company had $6,177,618 in cash and cash equivalents, of which $2,489,883 was invested in highly liquid AAA-rated tax-exempt money market funds.

Short Term Investments.  As of June 30, 2007 and 2006, the Company had $2,200,576 and $18,472,327, respectively, invested in a portfolio of periodic auction reset (“PAR”) securities, which have coupons that periodically reset to market interest rates at intervals ranging from 7 to 35 days. These PAR securities are being classified as short term investments and consist of AAA-rated tax-exempt municipal bonds. PAR securities are highly liquid and have minimal interest rate risk.

Accounts Receivable.  The Company sells natural gas and crude oil to a limited number of customers. In addition, the Company participates with other parties in the operation of natural gas and crude oil wells. Substantially all of the Company’s accounts receivables are due from either purchasers of natural gas and crude oil or participants in natural gas and crude oil wells for which the Company serves as the operator. Generally, operators of natural gas and crude oil properties have the right to offset future revenues against unpaid charges related to operated wells. The majority of our natural gas and crude oil sales are secured with letters of credit.

The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance. Provisions for bad debts and recoveries on accounts previously charged-off are added to the allowance.

F-8

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

Accounts receivable allowance for bad debt was $0 at June 30, 2007 and 2006. At June 30, 2007 and 2006, the carrying value of the Company’s accounts receivable approximates fair value.

Impairment of Long-Lived Assets.  The Company follows Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), which requires impairment losses to be recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the asset’s carrying amount. In the evaluation of the fair value and future benefits of long-lived assets, the Company performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets. If the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to its fair value.

Net Income (Loss) per Common Share.  Basic and diluted net income (loss) per common share have been computed in accordance with SFAS No. 128, “Earnings per Share”. Basic net income (loss) per common share is computed by dividing income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. See Note 7 – Net Income (Loss) Per Common Share for the calculations of basic and diluted net income (loss) per common share.

Income Taxes.  The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.

Concentration of Credit Risk.  Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.

Consolidated Statements of Cash Flows.  For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less when purchased to be cash equivalents. Significant transactions may occur that do not directly affect cash balances and, as such, are not disclosed in the Consolidated Statements of Cash Flows. Certain such non-cash transactions are disclosed in the Consolidated Statements of Shareholders’ Equity, including shares issued as compensation and issuance of stock options.

Fair Value of Financial Instruments.  The carrying amounts of the Company’s short-term financial instruments, including cash equivalents, short-term investments, trade accounts receivable and trade accounts payable, approximate their fair values based on the short maturities of those instruments. The Company’s long-term debt is variable rate debt and, as such, approximates fair value, as interest rates are variable based on prevailing market rates.

Successful Efforts Method of Accounting.  The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, and any such impairment is charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above. Depreciation, depletion and amortization is on a cost center by cost center basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.

F-9

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value. Approximately $0.2 million of impairment was reported for the fiscal year ended June 30, 2007 which was attributable to a write-down of costs relating to the Alta-Ellis #1 well in December 2006.

The Company amortizes and impairs natural gas and oil properties on a field-by-field cost center basis. Management believes this policy provides greater comparability with other successful efforts natural gas and oil companies by conforming to predominant industry practice. In addition, the field level is consistent with the Company’s operational and strategic assessment of its natural gas and oil investments.

In accordance with SFAS 144, the Company classified its $11.6 million property sale effective April 1, 2006, its $2.0 million property sale effective February 1, 2006, and its property sale to Edge Petroleum Corporation (“Edge Petroleum”) for $50.0 million, effective July 1, 2004, as discontinued operations. An integral and on-going part of our business strategy is to sell our proved reserves from time to time in order to generate additional capital to reinvest in our onshore and offshore exploration programs. Thus, it is our intent to remain an independent natural gas and oil company engaged in the exploration, production, and acquisition of natural gas and oil.

Principles of Consolidation.  The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries and affiliates, after elimination of all intercompany balances and transactions. Wholly-owned subsidiaries are fully consolidated. Exploration and development subsidiaries not wholly owned, such as 42.7% owned Republic Exploration LLC (“REX”), 50% owned Magnolia Offshore Exploration LLC (“MOE”), and 76.0% owned Contango Offshore Exploration LLC (“COE”), each as of June 30, 2007, are not controlled by the Company and are proportionately consolidated.

Upon the formation of REX and MOE, Contango was the only owner that contributed cash, and under the terms of the respective limited liability company agreements, was entitled to all of the ventures’ assets and liabilities until the ventures expended all of the Company’s initial cash contribution. The Company therefore consolidated 100% of the ventures’ net assets and results of operations. During the quarter ended December 31, 2002, both REX and MOE completed exploration activities to fully expend the Company’s initial cash contribution, thereby enabling each owner to share in the net assets of the venture based on their stated ownership percentages. Commencing with the quarter ended December 31, 2002, the Company began consolidating 33.3% and 50.0% of the net assets and results of operations of REX and MOE, respectively. The reduction of our ownership in the net assets of REX and MOE resulted in a non-cash exploration expense of approximately $4.2 million and $0.2 million, respectively in 2002. The other owners of REX contributed seismic data and related geological and geophysical services, while the other owner of MOE contributed geological and geophysical services in exchange for its ownership interest.

Upon the formation of COE, Contango was the only owner that contributed cash, but by agreement, the owners in COE immediately shared in the net assets of COE, including the Company’s initial cash contribution, based on their stated ownership percentages. The Company therefore consolidated 66.6% of the venture’s net assets and results of operations. The other owner of COE contributed geological and geophysical services in exchange for its ownership interest.

On September 2, 2005, the Company purchased an additional 9.4% ownership interest in each of REX and COE. Both interests were purchased from an existing owner, which prior to the sale, owned 33.3% of each of the two subsidiaries. As a result of these two purchases, the Company’s equity ownership interest in REX has increased from 33.3% to 42.7% and in COE from 66.6% to 76.0%. On September 2, 2005, an independent third party also purchased a 9.4% interest in each of REX and COE and the selling owner’s ownership interest thus decreased from 33.3% to 14.6% in each such entity.

F-10

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

Contango’s 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG”) is accounted for at cost. As a 10% limited partner, the Company has no ability to direct or control the operations or management of the general partner.

Contango’s 32% ownership in Contango Capital Partnership Management, LLC (“CCPM”), Contango’s 25% limited partnership interest in Contango Capital Partners, L.P. (“CCPLP”) and Contango’s 33% ownership of Moblize Inc. (“Moblize”) are accounted for using the equity method. Under the equity method, only Contango’s investment in and amounts due to and from the equity investee are included in the consolidated balance sheet. CCPLP formed the Contango Capital Partners Fund, LP (the “Fund”) in January 2005. The Fund owns equity interests in a portfolio of alternative energy companies. The Fund marks these equity interests to market according to fair market values on a quarterly basis.

Contango’s investments in Gridpoint, Inc. (“Gridpoint”) is accounted for using the cost method. Under the cost method, Contango records an investment in the stock of an investee at cost, and recognizes dividends received as income. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment.

Contango’s investment in Trulite, Inc. (“Trulite”) is accounted for in accordance with SFAS No. 115 (“SFAS 115”), “Accounting for Certain Investments in Debt and Equity Securities”. SFAS 115 applies to preferred stock and common stock, if ownership is less than 20%, or if ownership exceeds 20% but effective control (significant influence) is lacking. It is not applicable to investments under the equity method. Due to the nature and objective of our investment in Trulite, these securities are classified as available-for-sale securities under SFAS 115. Any unrealized gains or losses while marking these securities to market are reflected as a component of other comprehensive income at June 30, 2007.

Recent Accounting Pronouncements.  In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159 (“SFAS 159”), “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred. SFAS 159 becomes effective as of the beginning of the first fiscal year that begins after November 15, 2007, with early adoption permitted. However, entities may not retroactively apply the provisions of SFAS 159 to fiscal years preceding the date of adoption. We are currently evaluating the impact that SFAS 159 may have on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157 (“SFAS 157”), “Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value under Generally Accepted Accounting Principles and requires enhanced disclosures about fair value measurements. It does not require any new fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We are currently evaluating the impact SFAS 157 will have on the Company.

In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 and assessing the impact, if any, it may have on our financial position, results of operations or cash flows.

F-11

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

Stock-Based Compensation.  Effective July 1, 2001, the Company adopted the fair value based method prescribed in SFAS No. 123 (“SFAS 123”), “Accounting for Stock Based Compensation”. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. The fair value of each award is estimated as of the date of grant using the Black-Scholes options-pricing model. Effective July 1, 2005, the Company adopted SFAS No. 123 (revised 2004) (“SFAS 123(R)”), “Share-Based Payment”. Prior to the adoption of SFAS 123(R), the Company presented all benefits from the exercise of share-based compensation as operating cash flows in the statement of cash flows. SFAS 123(R) requires the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) to be classified as financing cash flows. The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants during the years ended June 30, 2007, 2006 and 2005, respectively: (i) risk-free interest rate of 5.0 percent, 5.1 percent and 3.68 percent, respectively; (ii) expected lives of five years; (iii) expected volatility of 56 percent, 40 percent and 40 percent, respectively; and (iv) expected dividend yield of zero percent.

Under the Company’s 1999 Stock Incentive Plan, as amended (the “1999 Plan” or the “Option Plan”), the Company’s Board of Directors may also grant restricted stock awards to officers or other employees of the Company. Restricted stock awards made under the 1999 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board. Restricted stock awards generally vest over a period of three years. Grants of service based restricted stock awards are valued at our common stock price at the date of grant. During the fiscal year ended June 30, 2007, the Company granted 16,750 shares of restricted stock to its employees, and 8,416 shares of restricted stock to its Board of Directors as part of its annual compensation. The shares of restricted stock granted to the Board of Directors vest over a period of one year.

On February 7, 2007, the Company granted 200,000 options to the Chairman and CEO at a fair value of $11.25 per option, to be expensed over the vesting period. During the years ended June 30, 2007, 2006 and 2005, the Company recorded a charge of $1.3 million, $856,412 and $385,193 in stock option expenses to general and administrative expense, respectively.

Derivative Instruments and Hedging Activities.  The Company did not enter into any derivative instruments or hedging activities for the fiscal years ended June 30, 2007, 2006 or 2005, nor did we have any open commodity derivative contracts at June 30, 2007.

Asset Retirement Obligation.  The Company adopted SFAS No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations” as of July 1, 2002. SFAS 143 requires the Company to record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. When the liability is initially recorded, a company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Due to the Company’s focus on offshore properties during the past two years, the ARO has increased from June 30, 2005. Activities related to the Company’s ARO during the year ended June 30, 2007 and 2006 are as follows:

	Year Ended June 30,
	2007			2006
Initial ARO as of July 1	$	665,458		$	957
Liabilities incurred during period		460,886			665,458
Liabilities settled during period		(264,000	)		(1,277	)
Accretion expense		-			320
Balance of ARO as of June 30	$	862,344		$	665,458

F-12

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

3.  Natural Gas and Oil Exploration Risk

The Company’s future financial condition and results of operations will depend upon prices received for its natural gas and oil production and the cost of finding, acquiring, developing and producing reserves. Substantially all of its production is sold under various terms and arrangements at prevailing market prices. Prices for natural gas and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control.

Other factors that have a direct bearing on the Company’s financial condition are uncertainties inherent in estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; the timing and costs of our future drilling; development and abandonment activities; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity. 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, the amount of reported assets, liabilities and contingencies, and proved natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas and oil activities.

4.  Credit Risk

The majority of the Company’s revenues for the fiscal year ended June 30, 2007 resulted from oil and gas sales to a single customer, Cokinos Energy Corporation. The receivables associated with these revenues are secured with letters of credit. We believe the loss of this purchaser would not have a material effect on our financial position or results of operation since there are numerous potential purchasers of our production.

5.  Sales to Major Customers

The customer base for the Company is primarily concentrated in the natural gas and oil exploration industry. Sales to Cokinos Energy Corporation were 67% of the Company’s total revenues for the fiscal year ended June 30, 2007.

6.  Sale of Properties – Discontinued Operations

On March 24, 2006, the Company’s Board of Directors approved the sale of all of the Company’s onshore producing assets in Texas and Alabama for an aggregate purchase price of $11.6 million. These properties were held by Contango STEP, LP (“STEP”), an indirect wholly-owned subsidiary of the Company. On April 28, 2006, the Company completed the sale of substantially all of these natural gas and oil interests for $11.1 million pursuant to a purchase and sale agreement. The sale of the remaining two wells under the same purchase and sale agreement for an aggregate purchase price of approximately $0.5 million was completed in June 2006. The sold properties had net reserves of approximately 203 thousand barrels (“Mbbl”) of oil and 849 million cubic feet (“MMcf”) of gas, or 2.1 billion cubic feet equivalent (“Bcfe”). The Company recognized a pre-tax gain of $6.2 million for the year ended June 30, 2006. This sale has been classified as discontinued operations in our financial statements for all periods presented.

In March 2006, the Company completed the sale of its interest in a producing well in Zapata County, Texas to an independent oil and gas company for approximately $2.0 million. Approximately 227 MMcf of proven reserves were sold. Pre-tax proceeds after netting adjustments were $2.0 million. The Company recognized a pre-tax gain on sale of $1.0 million for the year ended June 30, 2006. This sale has been classified as discontinued operations in our financial statements for all periods presented.

In December 2004, the Company sold producing properties consisting of 39 wells in south Texas, a majority of our natural gas and oil interests, to Edge Petroleum Corporation (“Edge Petroleum”) for $50.0

F-13

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

million. The sale was approved by a majority of the Company’s stockholders at a Special Meeting of Stockholders on December 29, 2004. Approximately 16 billion cubic feet equivalent per day (“Bcfe/d”) 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. 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 $16.3 million for the year ended June 30, 2005. Our sale of assets to Edge Petroleum has been classified as discontinued operations in our financial statements for all periods presented.

In accordance with SFAS 144, we classified our property sales as discontinued operations in our financial statements for all periods presented.

The Company did not have any discontinued operations for the fiscal year ended June 30, 2007. The summarized financial results for discontinued operations for the periods ended June 30, 2006 and 2005 are as follows:

Operating Results:

	June 30,
	2006			2005
Revenues	$	4,874,091		$	15,177,774
Operating (expenses) credits *		1,520,269			(1,215,544	)
Depreciation expenses		(966,734	)		(2,463,868	)
Exploration expenses		(1,092,741	)		(763,894	)
Gain on sale of discontinued operations		7,233,130			16,288,294
Gain before income taxes	$	11,568,015		$	27,022,762
Provision for income taxes		(4,048,805	)		(9,457,967	)
Gain from discontinued operations, net of income taxes	$	7,519,210		$	17,564,795

* Credits due to severance tax refunds

For the year ended June 30, 2006, operating expenses from discontinued operations resulted in a net credit of $1,520,269. The credit was attributable to credits issued for previously paid severance taxes. The Railroad Commission of Texas allows for a severance tax reduction on tight sand gas wells. As a result, some of our former south Texas formation properties, which were included in the sale of our south Texas natural gas and oil interests to Edge Petroleum, were eligible for severance tax reduction. By contractual agreement, revenues and expenses prior to July 1, 2004, the effective date of the sale, accrue to us.

F-14

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

7.  Net Income (Loss) Per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the fiscal years ended June 30, 2007, 2006 and 2005 is presented below:

	Year Ended June 30, 2007
	Net Income (Loss)			Shares	Per Share
Loss from continuing operations including preferred dividends	$	(3,234,273	)	15,430,146	$	(0.21	)
Basic Earnings per Share:
Net loss	$	(3,234,273	)	15,430,146	$	(0.21	)
Effect of Potential Dilutive Securities:
Stock options		-		(a)
Series D preferred stock		(a)		(a)
Series E preferred stock		(a)		(a)
Loss from continuing operations	$	(3,234,273	)	15,430,146	$	(0.21	)
Diluted Earnings per Share:
Net loss	$	(3,234,273	)	15,430,146	$	(0.21	)
Anti-dilutive Securities:
Shares assumed not issued from options to purchase common shares as income from continuing operations was in a loss position for the period	$	-		1,026,000
Series D Preferred Stock	$	314,722		447,061	$	0.70
Series E Preferred Stock	$	225,000		94,909	$	2.37
(a) Anti-dilutive.
	Year Ended June 30, 2006
	Net Income (Loss)			Shares	Per Share
Loss from continuing operations including preferred dividends	$	(8,327,173	)	14,760,268	$	(0.56	)
Discontinued operations, net of income taxes		7,519,210		14,760,268		0.51
Basic Earnings per Share:
Net loss	$	(807,963	)	14,760,268	$	(0.05	)
Effect of Potential Dilutive Securities:
Stock options and warrants		-		(a)
Series C preferred stock		(a)		(a)
Series D preferred stock		(a)		(a)
Loss from continuing operations	$	(8,327,173	)	14,760,268	$	(0.56	)
Discontinued operations, net of income taxes		7,519,210		14,760,268		0.51
Diluted Earnings per Share:
Net loss	$	(807,963	)	14,760,268	$	(0.05	)
Anti-dilutive Securities:
Shares assumed not issued from options to purchase common shares as income from continuing operations was in a loss position for the period	$	-		927,500	$	7.78
Series D Preferred Stock	$	601,000		833,330	$	0.72
Series C Preferred Stock	$	21,000		1,166,667	$	0.02

F-15

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

7.  Net Income (Loss) Per Common Share – continued

	Year Ended June 30, 2005
	Net Income (Loss)			Shares	Per Share
Loss from continuing operations including preferred dividends	$	(5,566,859	)	13,089,332	$	(0.42	)
Discontinued operations, net of income taxes		17,564,795		13,089,332		1.34
Basic Earnings per Share:
Net income	$	11,997,936		13,089,332	$	0.92
Effect of Potential Dilutive Securities:
Stock options and warrants		-		(a)
Series C preferred stock		(a)		(a)
Loss from continuing operations	$	(5,566,859	)	13,089,332	$	(0.42	)
Discontinued operations, net of income taxes		17,564,795		13,089,332		1.34
Diluted Earnings per Share:
Net income	$	11,997,936		13,089,332	$	0.92
Anti-dilutive Securities:
Shares assumed not issued from options to purchase common shares as income from continuing operations was in a loss position for the period	$	-		1,301,000	$	6.38
Series C Preferred Stock	$	420,000		1,166,667	$	0.36
(a) Anti-dilutive

8.  Acquisition of Interest in Partially-Owned Subsidiaries and Overriding Royalties

On September 2, 2005, we purchased an additional 9.4% ownership interest in each of our two partially-owned offshore Gulf of Mexico exploration subsidiaries, REX for $5.6 million and COE for $1.9 million, for a total expenditure of $7.5 million. Both interests were purchased from Juneau Exploration, L.P. (“JEX”), which prior to the sale, owned 33.3% of each of the two subsidiaries. As a result of these two purchases, the Company’s equity ownership interest in REX has increased from 33.3% to 42.7% and in COE from 66.6% to 76.0%. The purchases were financed from the Company’s existing cash on hand. An independent third party also purchased a 9.4% interest in each of REX and COE from JEX for the same total purchase price of $7.5 million. JEX will continue in its capacity as the managing member of both REX and COE and following these two sales, now owns a 14.6% interest in each of REX and COE.

During the previous fiscal year ended June 30, 2006, the Company allocated the purchase price to the net assets acquired (“purchase price allocation”). These assets include planned drilling commitments, unevaluated exploration blocks, and proven developed producing (“PDP”) properties. A significant portion of the purchase price allocation was allocated to our Eugene Island 10 (“Dutch”) and Grand Isle 63/72/73 (“Liberty”) exploration prospects, which proved to be discoveries. During the previous fiscal year ended June 30, 2006, we wrote off $0.3 million of the purchase price relating to our Main Pass 221 prospect and $0.3 million relating to our West Delta 43 prospect, because they were dry holes; and $0.1 million relating to our East Cameron 107 prospect, as a result of the expiration of its lease.

On November 7, 2005, the Company, in a separate transaction, also acquired certain overriding royalty interests in REX, COE and MOE offshore prospects for the purchase price of $1.0 million.

9.  Series E Perpetual Cumulative Convertible Preferred Stock

On May 17, 2007, we sold $30.0 million of our Series E preferred stock to a group of private investors. The Series E preferred stock is perpetual and cumulative, is senior to our common stock and is convertible at any

F-16

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

time into shares of our common stock at a price of $38.00 per share. Each record holder of Series E preferred stock is entitled to one vote per share for each share of common stock into which each share of Series E preferred stock is convertible. The dividend on the Series E preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per annum. Our registration statement filed with the Securities and Exchange Commission, covering the 789,468 shares of common stock issuable upon conversion of the Series E preferred stock was not yet effective as of June 30, 2007. Net proceeds associated with the private placement of the Series E preferred stock was approximately $28.8 million, net of stock issuance costs.

Holders of common stock and holders of Series E preferred stock vote as one class for the election of directors and most other matters. Upon any liquidation or dissolution of the Company, the holders of common stock are entitled to receive a pro rata share of all of the assets remaining available for distribution to shareholders after settlement of all liabilities and liquidating preferences of preferred stockholders.

10.  Series D Perpetual Cumulative Convertible Preferred Stock

On July 15, 2005, we sold $10.0 million of our Series D preferred stock to a group of private investors. The Series D preferred stock is perpetual and cumulative, is senior to our common stock and is convertible at any time into shares of our common stock at a price of $12.00 per share. Each record holder of Series D preferred stock is entitled to one vote per share for each share of common stock into which each share of Series D preferred stock is convertible. The dividend on the Series D preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per annum. Our registration statement filed with the Securities and Exchange Commission, covering the 833,330 shares of common stock issuable upon conversion of the Series D preferred stock, became effective on October 26, 2005. Net proceeds associated with the private placement of the Series D preferred stock was approximately $9.6 million, net of stock issuance costs.

In November 2006, two Series D preferred stockholders voluntarily elected to convert a total of 100 shares of Series D preferred stock to 41,666 shares of common stock, par value $0.04 per share. The converted shares of Series D preferred stock had a face value of $0.5 million.

On January 15, 2007, we exercised our mandatory conversion rights pursuant to the terms of our Series D preferred stock, and converted all of the remaining 1,900 shares of our Series D preferred stock issued and outstanding into 791,664 shares of our common stock. The outstanding shares of the Series D preferred stock had a face value of $9.5 million.

11.  Investment in Freeport LNG

As of June 30, 2007, the Company has invested $3.2 million and owns a 10% limited partnership interest in Freeport LNG, a limited partnership formed to develop a 1.75 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 900 MMcf/d of regasification capacity with a 25 year term, purchased a 50% interest in the general partner managing the Freeport LNG project and agreed to provide certain construction funding to the venture. This construction funding is non-recourse to Contango. The Dow Chemical Company has executed a terminal use agreement for regasification capacity of 500 MMcf/d with a 20 year term and, in an unrelated transaction with another limited partner, has purchased a 15% limited partnership interest in Freeport LNG. Mitsubishi Corporation has also executed a terminal use agreement for regasification capacity of 150 MMCf/d with a 15 year term. 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 1.75 Bcf/day facility commenced on January 17, 2005. The engineering, procurement and construction contractor is a consortium of Technip USA, Zachry Construction of San Antonio, and Saipem SpA of Italy.

F-17

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

12.  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 the company. We account for this investment under the equity method. Trulite is a publicly traded company. We account for this investment in accordance with 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 $.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 approximately $55,000 in interest income from the Trulite notes. Please see Note 18 – Related Party Transactions, 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

F-18

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

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.

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.

13.  Income Taxes

Actual income tax expense (benefit) differs from income tax expense (benefit) computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income (loss) as follows:

	Year Ended June 30,
	2007					2006					2005
Provision (benefit) at statutory tax rate	$	(1,409,704	)	-35.0	%	$	(142,373	)	-35.0	%	$	6,694,724	35.0	%
State income tax provision (benefit), net of federal benefit		-		-			94,900		23.5	%		-	-
Permanent differences		13,604		0.3	%		(185,315	)	-45.5	%		-	-
Other		62,926		1.6	%		32,970		8.0	%		15,122	0.08	%
Income tax provision (benefit)	$	(1,333,174	)	-33.10	%	$	(199,818	)	-49.00	%	$	6,709,846	35.08	%

The provision (benefit) for income taxes for the periods indicated are comprised of the following:

	Year Ended June 30,
	2007			2006			2005
Current:
Federal	$	(2,025,992	)	$	(352,957	)	$	9,983,768
State		-			146,000			-
Total	$	(2,025,992	)	$	(206,957	)	$	9,983,768
Deferred:
Federal	$	692,818		$	7,139		$	(3,273,922	)
State		-			-			-
Total	$	692,818		$	7,139		$	(3,273,922	)
Total:
Federal	$	(1,333,174	)	$	(345,818	)	$	6,709,846
State		-			146,000			-
Total	$	(1,333,174	)	$	(199,818	)	$	6,709,846

The Company’s permanent benefits relate mainly to non-taxable interest on municipal bonds.

F-19

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

The net deferred tax asset (liability) is comprised of the following:

	Year Ended June 30,
	2007			2006		2005
Deferred tax asset:
Net operating loss carryover	$	13,254,460		$	2,805,770	$	-
AMT credit carryforward		523,149			-		-
Temporary basis differences in natural gas and oil properties and other		(10,400,593	)		1,649,420		4,462,329
Net deferred tax asset	$	3,377,016		$	4,455,190	$	4,462,329

At June 30, 2007, the Company had a net operating loss for federal income tax purposes of $13.3 million, which can be carried back two years and forward twenty years. Realization of net deferred tax assets associated with net operating loss carryovers is dependent upon generating sufficient taxable income prior to its expiration. The Company has not established a valuation allowance for deferred tax assets, as management currently believes that it is more likely than not that the net operating loss carryover will be fully utilized in the carryback or carryover period.

14.  Long-Term Debt

The Company has $20.0 million outstanding under a three-year $20.0 million secured term loan facility (the “RBS Facility”) with The Royal Bank of Scotland plc (“RBS”). The RBS Facility is secured with the stock of Contango Sundance Inc. (“Sundance”), our wholly-owned subsidiary. Sundance owns a 10% limited partnership interest in Freeport LNG, which owns the Freeport LNG facility. Borrowings under the RBS Facility bear interest, at the Company’s option, at either (i) 30 day LIBOR, (ii) 60 day LIBOR, (iii) 90 day LIBOR or (iv) 6 month LIBOR, all plus 6.5%. Interest is due at the end of the LIBOR period chosen. The average interest rate charged for the fiscal year ended June 30, 2007 was 11.91%. The principal is due April 27, 2009, but we may prepay after April 27, 2008 with no prepayment penalty.

On January 30, 2007, the Company completed the arrangement of a $30.0 million secured term loan agreement with a private investment firm (the “Term Loan Agreement”). The Term Loan Agreement is secured with substantially all the assets of the Company, except for the stock of Sundance, which is pledged to RBS under our RBS Facility. As of June 30, 2007, the Company had no amounts outstanding under the Term Loan Agreement. Borrowings bear interest at 30 day LIBOR plus 5.0%. The average interest rate charged for the fiscal year ended June 30, 2007 was 10.32%. Accrued interest is due monthly. The principal is due December 31, 2008, but we may prepay at any time with no prepayment penalty. An arrangement fee of 1%, or $300,000, was paid in connection with the term loan. Additionally, we pay a non-use fee in the amount of 1.50% per annum multiplied by such non-funded amount.

Both the Term Loan Agreement and the RBS Facility require a minimum level of working capital and contain certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required working capital or comply with certain covenants in the Term Loan Agreement and RBS Facility could result in a default and acceleration of all indebtedness under such credit facilities. As of June 30, 2007, the Company was in compliance with its financial covenants, ratios and other provisions of the Term Loan Agreement and RBS Facility.

On December 14, 2006, the Company terminated its $0.1 million credit facility with Guaranty Bank, FSB. The Company had no debt outstanding under this credit facility at the time of termination and was in compliance with its financial covenants, ratios and other provisions.

F-20

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

15.  Commitments and Contingencies

Operating Leases.  Contango leases its office space and certain other equipment. As of June 30, 2007 minimum future lease payments are as follows:

Fiscal years Ending June 30,
2008		134,115
2009		135,858
2010		128,152
2011		130,840
2012 and thereafter		43,912
Total	$	572,877

The amount incurred under operating leases during the years ended June 30, 2007, 2006 and 2005 was $173,259, $139,744 and $110,404, respectively.

Dayrates.  Once we have completed drilling Mary Rose #1, should we choose not to retain the drilling rig, we are committed to pay a dayrate equal to $48,000 per day (approximately $19,000 per day, net to Contango) for 53 days, or until the rig is hired by another company, whichever occurs first.

16.  Stock Based Compensation

In September 1999, the Company established the Contango Oil & Gas Company 1999 Stock Incentive Plan (the “1999 Plan” or the “Option Plan”). Under the Option Plan, the Company may issue up to 2,500,000 shares of common stock with an exercise price of each option equal to or greater than the market price of the Company’s common stock on the date of grant, but in no event less than $2.00 per share. The Company may grant key employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options generally expire after five or ten years. The vesting schedule varies, but vesting generally occurs over a two-year period (1/3 immediately, 1/3 one year from the date of grant and 1/3 two years from the date of grant) or four-year period (1/4 one year from the date of grant and 1/4 two years, three years and four years from the date of grant). As of June 30, 2007, options under the Option Plan to acquire 1,026,000 shares of common stock at prices between $3.00 and $21.00 per share were outstanding.

A summary of the status of the Option Plan and those options granted outside of the Option Plan as of June 30, 2007, 2006 and 2005, and changes during the fiscal years then ended, is presented in the table below:

	Year Ended June 30,
	2007					2006					2005
	Shares Under Options			Weighted Average Exercise Price		Shares Under Options			Weighted Average Exercise Price		Shares Under Options			Weighted Average Exercise Price
Outstanding, beginning of year		960,500		$	7.97		1,176,000		$	6.74		1,279,021		$	4.37
Granted		213,500		$	20.42		76,000		$	12.31		454,500		$	9.57
Exercised		(107,750	)	$	4.93		(284,000	)	$	4.10		(557,521	)	$	3.65
Cancelled		(40,250	)	$	8.14		(7,500	)	$	5.17		-		$	-
Outstanding, end of year		1,026,000		$	10.87		960,500		$	7.97		1,176,000		$	6.74
Aggregate intrinsic value	$	26,079,555				$	5,926,285				$	2,892,960
Exercisable, end of year		671,500		$	9.04		561,292		$	6.82		501,167		$	5.01
Aggregate intrinsic value	$	18,301,165				$	4,108,657				$	2,099,888
Available for grant, end of year		469,333					642,583					716,083
Weighted average fair value of options granted during the year (1)	$	10.85				$	5.17				$	3.46

F-21

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

(1) The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants during the years ended June 30, 2007, 2006 and 2005, respectively: (i) risk-free interest rate of 5.0 percent, 5.1 percent and 3.68 percent; (ii) expected lives of five years for the Option Plan and other options; (iii) expected volatility of 56 percent, 40 percent and 40 percent; and (iv) expected dividend yield of zero percent.

The following table summarizes information about options that were outstanding at June 30, 2007:

	Options Outstanding				Options Exercisable
Range of Exercise Price	Number of Shares Under Outstanding Options	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number of Shares Under Outstanding Options	Weighted Average Exercise Price
$3.00 - $3.99	35,000	5.0	$	3.00	35,000	$	3.00
$4.00 - $4.99	50,000	1.0	$	4.05	50,000	$	4.05
$6.00 - $6.99	266,000	1.9	$	6.78	266,000	$	6.78
$7.00 - $7.99	26,000	3.3	$	7.73	26,000	$	7.73
$8.00 - $8.99	4,000	5.3	$	8.35	4,000	$	8.35
$9.00 - $9.99	114,000	3.1	$	9.30	59,000	$	9.29
$10.00 - $10.99	250,000	3.0	$	10.23	125,000	$	10.23
$11.00 - $11.99	50,000	4.0	$	11.59	19,833	$	11.55
$12.00 - $12.99	18,500	3.9	$	12.65	12,000	$	12.65
$14.00 - $14.99	12,500	4.4	$	14.14	8,000	$	14.14
$21.00 - $21.99	200,000	4.6	$	21.00	66,667	$	21.00
	1,026,000	3.1	$	10.87	671,500	$	9.04

Effective July 1, 2001, the Company changed it method of accounting for employee stock-based compensation to the fair value method prescribed in SFAS 123. Effective July 1, 2005, the Company adopted SFAS 123(R). Prior to the adoption of SFAS 123(R), we presented all tax benefits resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123(R) requires that cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) be classified as financing cash flows. For the fiscal years ended June 30, 2007 and 2006, $188,897 and $359,772 respectively, of such excess tax benefits were classified as financing cash flows. See Note 2 – Summary of Significant Accounting Policies.

All employee stock option grants are expensed over the stock options vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. During the fiscal year-ended June 30, 2007, 2006 and 2005, the Company recorded stock option expense of $1.3 million, $0.9 million and $0.4 million, respectively.

As of June 30, 2007, we have approximately $2.4 million of total unrecognized compensation cost related to non-vested awards granted under our various share-based plans, which we expect to recognize over an average period of three years.

The aggregate intrinsic values of the options exercised during fiscal years 2007, 2006 and 2005 were $1.9 million, $2.2 million and $2.2 million, respectively.

On July 5, 2006, the Company awarded a total of 16,750 shares of restricted stock under the 1999 Plan to certain employees. The restricted stock vests over a three year period, commencing on the grant date. The fair value of restricted stock was approximately $239,000 and is being recognized as compensation expense over the three year vesting period. On November 16, 2006, the Company’ awarded a total of 8,416 shares of restricted stock under the 1999 Plan to its Board of Directors. The restricted stock vests over a one year period, commencing on the grant date. The fair value of restricted stock was approximately $144,000.

F-22

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

For the year ended June 30, 2007, the Company recognized $153,979 in compensation expense relating to restricted stock awards. A summary of the Company’s restricted stock as of June 30, 2007, is as follows:

	Number of Shares		Weighted Average Fair Value Per Share
Nonvested balance at June 30, 2006	-			-
Granted	25,166		$	15.21
Vested	(9,791	)		15.48
Forfeited	-			-
Nonvested balance at June 30, 2007	15,375		$	15.04

17.  Warrants

As of June 30, 2007, the Company had no outstanding warrants. The final remaining issued warrants were exercised during the fiscal year ended June 30, 2006. The Company reserved an equal number of shares of common stock for issuance upon the exercise of its outstanding warrants. A summary of the Company warrants as of June 30, 2007, 2006 and 2005, and changes during the fiscal years then ended, is presented in the table below:

	Year Ended June 30,
	2007		2006				2005
	Number of Shares Under Outstanding Warrants	Weighted Average Exercise Price	Number of Shares Under Outstanding Warrants		Weighted Average Exercise Price		Number of Shares Under Outstanding Warrants		Weighted Average Exercise Price
Outstanding, beginning of year	-		125,000		$	3.06	687,500		$	2.39
Exercised	-		(125,000	)	$	3.06	(562,500	)	$	2.00
Cancelled	-	-	-			-	-		$	-
Outstanding, end of year	-	-	-			-	125,000		$	3.06
Exercisable, end of year	-	-	-			-	125,000		$	3.06

We received cash from options and warrants exercised during the years ended June 30, 2007, 2006 and 2005 of $0.5 million, $1.5 million and $1.9 million, respectively. The impact of these cash receipts is included in financing activities in the accompanying Consolidated Statements of Cash Flows.

18.  Related Party Transactions

In the ordinary course of business, the Company contracted with Moblize to install automation equipment that will allow COI to remotely monitor, control and record, in real time, daily production volumes from the Grand Isle 72 #1 well. For the year ended June 30, 2007, the Company paid approximately $85,000 to Moblize for such services.

On October 26, 2006, REX executed a Demand Promissory Note (the “REX Note”) with a private investment firm which is non-recourse to Contango. Under the terms of the REX Note, REX can borrow up to $50.0 million at a per annum rate of 11.5% for the first advance, and a per annum rate of LIBOR plus 6.0% for each additional advance. All advances are payable in full on the earlier of October 26, 2008 or upon demand. As of June 30, 2007, REX had borrowed $20.0 million under the REX Note. The Company is not a party to or guarantor of the REX Note, but as a result of our proportionate consolidation of REX, $8.5 million is reflected as a current liability on our balance sheet as of June 30, 2007. The REX Note is secured by substantially all the assets of REX including the production attributable to REX from our Dutch and Mary Rose exploration discoveries in the Gulf of Mexico. For the fiscal year ended June 30, 2007, the Company’s proportionate share of such interest expense was approximately $0.5 million.

F-23

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

On August 9, 2006, the Company executed the first of four promissory notes with Trulite (the “Trulite Notes”), whereby Trulite borrowed funds from the Company, agreeing to pay all accrued and unpaid interest on the due date. The Trulite Notes are summarized below:

Date of Note	Principal Amount	Initial Interest Rate	Date Interest Rate Changed to Prime + 3%	Date Interest Rate Changes to Prime + 4%	Due Date
August 9, 2006	$125,000	11.25%	February 9, 2007	July 2, 2007	December 31, 2007
November 22, 2006	400,000	11.25%	April 25, 2007	July 2, 2007	December 31, 2007
February 6, 2007	240,000	11.25%	n/a	August 6, 2007	December 31, 2007
May 30, 2007	240,000	11.25%	October 23, 2007	n/a	February 19, 2008

On April 5, 2007, the Company entered into a subscription agreement, as amended from time to time (the “Subscription Agreement”) with Trulite, whereby both parties agreed to convert the aggregate principal balance of the first three Trulite Notes, totaling $765,000, and all accrued but unpaid interest into shares of Trulite common stock. The number of shares to be issued is dependant upon the average closing sale price for the common stock of Trulite as quoted on the Over the Counter Bulletin Board for a specified duration as detailed in the Subscription Agreement, and will take place once Trulite has a specified number of shares outstanding, as detailed in the Subscription Agreement. The fourth Trulite Note of $240,000, plus all accrued but unpaid interest, will be repaid on the due date. For the fiscal year ended June 30, 2007, the Company earned approximately $55,000 in interest income from the Trulite Notes.

In July 2006, the Company purchased options from one of the members of the Board of Directors for $91,190. We do not have a publicly announced program to repurchase shares of our common stock.

On March 31, 2006, COE executed a Promissory Note (the “COE Note”) to the Company to finance its share of development costs in Grand Isle 72, in the aggregate principal amount of up to $2.8 million. The COE Note is payable upon demand and bears interest at a per annum rate of 10%. On March 20, 2007, the aggregate principal amount was increased to $3.75 million. On April 24, 2007, the aggregate principal amount of the COE Note was increased to $5.0 million. As of June 30, 2007, the outstanding principal balance under the COE Note was $4.3 million. As of June 30, 2007, the amount of accrued interest thereon was approximately $0.2 million.

19.  Suspended Well Costs

The Company’s net changes in suspended well costs for the year ended June 30, 2007, in accordance with FASB Staff Position No. 19-1, “Accounting for Suspended Well Costs”, are presented below:

	Year Ended June 30, 2007
Balance at June 30, 2006	$	-
Additions pending the determination of economic resources		3,010,401
Reclassification to proved reserves		-
Charged to dry hole costs		-
Balance at June 30, 2007	$	3,010,401

20.  Subsequent Events

On July 2, 2007, REX borrowed an additional $6.0 million under the REX Note, and on August 23, 2007, REX borrowed an additional $5.0 million under the REX Note, bringing the total amount outstanding under the REX Note to $31.0 million. The interest rate on both borrowings is a per annum rate of LIBOR plus six percent. The note is non-recourse to Contango. Contango’s share of such obligation and interest expense will be reflected in future financial statements as a result of our proportionate consolidation of REX.

F-24

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

On August 20, 2007, the Company executed a fifth promissory note with Trulite to loan the company $250,000. This note bears interest at a per annum rate of 12.25% until February 14, 2008, at which point the per annum rate will change to prime rate plus four percentage points until May 16, 2008, which is when the Trulite Note plus all accrued and unpaid interest is due. This note is not subject to the subscription agreement discussed earlier in Note 18 – Related Party Transactions.

F-25

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

The following disclosures provide unaudited information required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities”.

Costs Incurred.  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:

	Year Ended June 30,
	2007		2006		2005
Property Acquisition Costs:
Unproved	$	3,571,830	$	14,609,232	$	248,634
Proved		-		-		-
Exploration costs		72,888,603		19,529,607		9,428,002
Developmental costs		1,453,066		590,395		-
Capitalized interest		1,083,693		149,365		-
Total costs	$	78,997,192	$	34,878,599	$	9,676,636

Natural Gas and Oil Reserves.  Proved reserves are estimated quantities of natural gas and oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that reasonably can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved natural gas and oil reserve quantities at June 30, 2007, 2006 and 2005, and the related discounted future net cash flows before income taxes are based on estimates prepared by W.D. Von Gonten & Co. and William M. Cobb & Associates, Inc., petroleum engineering. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.

F-26

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

The Company’s net ownership interests in estimated quantities of proved natural gas and oil reserves and changes in net proved reserves as of June 30, 2007, 2006 and 2005, all of which are located in the continental United States, are summarized below:

	Oil and Condensate		Natural Gas
	(MBbls)		(MMcf)
Proved Developed and Undeveloped Reserves as of:
June 30, 2004	297		15,633
Sale of reserves	(267	)	(14,413	)
Discoveries	69		166
Recoveries and revisions	29		1,649
Production	(51	)	(2,124	)
June 30, 2005	77		911
Sale of reserves	(203	)	(1,076	)
Discoveries	174		3,813
Recoveries and revisions	-		172
Production	(37	)	(456	)
June 30, 2006	11		3,364
Sale of reserves	(2	)	(414	)
Discoveries	1,188		75,662
Recoveries and revisions	6		1,732
Production	(39	)	(2,452	)
June 30, 2007	1,164		77,892
Proved Developed Reserves as of:
June 30, 2004	296		15,543
June 30, 2005	77		911
June 30, 2006	11		1,876
June 30, 2007	827		57,721

F-27

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Standardized Measure.  The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved natural gas and oil reserves as of June 30, 2007, 2006 and 2005 are shown below:

	As of June 30,
	2007			2006			2005
Future cash flows	$	575,634,244		$	20,342,459		$	10,639,610
Future operating expenses		(56,151,152	)		(2,957,249	)		(2,121,836	)
Future development costs		(51,478,940	)		(4,436,360	)		(72,393	)
Future income tax expenses		(114,832,834	)		(1,389,931	)		(2,255,844	)
Future net cash flows		353,171,318			11,558,919			6,189,537
10% annual discount for estimated timing of cash flows		(100,874,043	)		(3,824,813	)		(938,937	)
Standardized measure of discounted future net cash flows	$	252,297,275		$	7,734,106		$	5,250,600

Future cash flows are computed by applying fiscal year-end prices of natural gas and oil to year-end quantities of proved natural gas and oil reserves. Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved natural gas and oil reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s natural gas and oil properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations.

F-28

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Change in Standardized Measure.  Changes in the standardized measure of future net cash flows relating to proved natural gas and oil reserves are summarized below:

	Year Ended June 30,
	2007			2006			2005
Changes due to current year operation:
Sales of natural gas and oil, net of natural gas and oil operating expenses	$	(17,015,997	)	$	(7,301,314	)	$	(15,031,481	)
Extensions and discoveries		326,092,883			17,872,465			4,027,189
Net change in prices and production costs		1,721,445			249,397			1,087,868
Change in future development costs		2,737,444			(5,660	)		-
Revisions of quantity estimates		5,450,220			1,023,322			6,894,659
Sale of reserves		(1,529,012	)		(11,517,747	)		(54,312,903	)
Accretion of discount		885,209			708,142			5,976,673
Change in the timing of production rates and other		1,985,288			742,058			(1,327,312	)
Changes in income taxes		(75,764,311	)		712,843			12,957,155
Net change		244,563,169			2,483,506			(39,728,152	)
Beginning of year		7,734,106			5,250,600			44,978,752
End of year	$	252,297,275		$	7,734,106		$	5,250,600

F-29

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY RESULTS OF OPERATIONS (Unaudited)

Quarterly Results of Operations.  The following table sets forth the results of operations by quarter for the years ended June 30, 2007 and 2006:

	Quarter Ended
	Sept. 30,			Dec. 31,			Mar. 31,			June 30,
	($000, except per share amounts)
Fiscal Year 2007:
Revenues from continuing operations	$	1,192		$	850		$	5,416		$	11,230
Income (loss) from continuing operations (1)	$	(256	)	$	(2,317	)	$	179		$	(301	)
Net income (loss) attributable to common stock	$	(406	)	$	(2,459	)	$	156		$	(525	)
Net income (loss) per share (2):
Basic:
Continuing operations	$	(0.03	)	$	(0.16	)	$	0.01		$	(0.03	)
Diluted:
Continuing operations	$	(0.03	)	$	(0.16	)	$	0.01		$	(0.03	)
Fiscal Year 2006:
Revenues from continuing operations	$	148		$	44		$	123		$	605
Revenues from discontinued operations	$	1,043		$	1,779		$	1,555		$	497
(Loss) from continuing operations (1)	$	(477	)	$	(808	)	$	(855	)	$	(5,586	)
Discontinued operations, net of income taxes	$	688		$	589		$	1,755		$	4,487
Net income (loss) attributable to common stock	$	60		$	(368	)	$	749		$	(1,249	)
Net income (loss) per share (2):
Basic:
Continuing operations	$	(0.04	)	$	(0.07	)	$	(0.07	)	$	(0.38	)
Discontinued operations	$	0.05		$	0.04		$	0.12		$	0.30
Diluted:
Continuing operations	$	(0.04	)	$	(0.07	)	$	(0.07	)	$	(0.38	)
Discontinued operations	$	0.05		$	0.04		$	0.12		$	0.30

(1) Represents natural gas and oil sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, impairment of natural gas and oil properties, and general and administrative expense and other income after benefit (expense) for income taxes.

(2) The sum of the individual quarterly earnings (loss) per share may not agree with year-to-date earnings (loss) per share as each quarterly computation is based on the income or loss for that quarter and the weighted average number of common shares outstanding during that quarter.

F-30