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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
 
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended June 30, 2008
o
  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 o     No þ
 
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 o     No þ
 
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 þ     No o
 
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.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer o
  Accelerated filer þ   Non-accelerated filer o   Smaller reporting company o
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
At December 31, 2007, 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 $649,840,517. As of August 22, 2008, there were 16,824,246 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.
 


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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED JUNE 30, 2008
 
TABLE OF CONTENTS
 
                 
        Page
 
      Business     1  
          Overview     1  
          Our Strategy     1  
          Exploration Alliance with JEX     2  
          Offshore Gulf of Mexico Exploration Joint Ventures     2  
          Contango Operators, Inc.      3  
          Contango Resources Company     3  
          Offshore Properties     5  
          Contango Venture Capital Corporation     7  
          Property Sales and Discontinued Operations     8  
          Marketing and Pricing     8  
          Competition     9  
          Governmental Regulations     9  
          Employees     10  
          Directors and Executive Officers     11  
          Corporate Offices     13  
          Code of Ethics     13  
          Available Information     13  
      Risk Factors     13  
      Unresolved Staff Comments     21  
      Properties     21  
          Production, Prices and Operating Expenses     21  
          Development, Exploration and Acquisition Capital Expenditures     22  
          Drilling Activity     22  
          Exploration and Development Acreage     22  
          Productive Wells     23  
          Natural Gas and Oil Reserves     23  
      Legal Proceedings     24  
      Submission of Matters to a Vote of Security Holders     24  


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        Page
 
PART II
      Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     24  
      Selected Financial Data     27  
      Management’s Discussion and Analysis of Financial Condition and Results of Operations     28  
        Overview     28  
          Results of Operations     29  
          Capital Resources and Liquidity     32  
          Off Balance Sheet Arrangements     33  
          Contractual Obligations     33  
          Credit Facility     33  
          Application of Critical Accounting Policies and Management’s Estimate     34  
          Recent Accounting Pronouncements     35  
      Quantitative and Qualitative Disclosure about Market Risk     36  
      Financial Statements and Supplementary Data     36  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     36  
      Controls and Procedures     36  
      Other Information     39  
 
PART III
      Directors, Executive Officers and Corporate Governance     39  
      Executive Compensation     39  
      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     39  
      Certain Relationships and Related Transactions, and Director Independence     39  
      Principal Accountant Fees and Services     39  
 
PART IV
      Exhibits and Financial Statement Schedules     39  
 Assignment of Overriding Royalty Interest
 Assignment of Overriding Royalty Interest
 Assignment of Overriding Royalty Interest
 Assignment of Overriding Royalty Interest
 Assignment of Overriding Royalty Interest
 Assignment of Overriding Royalty Interest
 Assignment of Overriding Royalty Interest
 Amended and Restated Limited Liability Company Agreement
 Amended and Restated Term Loan Agreement
 List of Subsidiaries
 Organizational Chart
 Consent of William M. Cobb & Associates, Inc.
 Consent of Grant Thornton LLP
 Consent of W.D. Von Gonten & Co.
 Certification Required by Rules 13a-14 and 15d-14
 Certification Pursuant to 18 U.S.C. 1350


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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
 
Some of the statements made in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. These include such matters as:
 
  •  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
 
Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not 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
 
  •  Operating hazards attendant to the natural gas and oil business


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  •  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
 
  •  Successful commercialization of alternative energy technologies
 
  •  Drilling and operating costs, production rates and ultimate reserve recoveries in our Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) acreage.
 
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 14 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 business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico. Contango Operators, Inc. (“COI”) and Contango Resources Company (“CRC”), our wholly-owned subsidiaries, act as operator on certain offshore prospects.
 
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 Juneau Exploration, L.P., our alliance partner.  We depend totally upon our alliance partner, Juneau Exploration, L.P. (“JEX”), for prospect generation expertise. JEX is experienced and has a successful track record in exploration.
 
Using our limited capital availability to increase our reward/risk potential on selective prospects.  We have concentrated our risk investment capital in our offshore Gulf of Mexico prospects. Exploration prospects are inherently risky as they require large amounts of capital with no guarantee of success. COI and CRC drill and operate 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 and CRC were 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 the Company 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.
 
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 offshore exploration activities. Since its inception, the Company has sold approximately $484 million worth of natural gas and oil properties, and views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, and as a source of funds for potentially higher rate of return natural gas and oil exploration opportunities.
 
Controlling general and administrative and geological and geophysical costs.  Our goal is to be among the most efficient in the industry in revenue and profit per employee and among the lowest in general and administrative costs. With respect to our onshore prospects, we plan to continue outsourcing our geological, geophysical, and reservoir engineering and land functions, and partnering with cost efficient operators. We have six employees.
 
Structuring transactions to share risk.  JEX, our alliance partner, shares 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 23.1% of our common stock.


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Exploration 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”) and Contango Offshore Exploration, LLC (“COE”) (see “Offshore Gulf of Mexico Exploration Joint Ventures” below).
 
Offshore Gulf of Mexico Exploration Joint Ventures
 
Contango directly and through REX and COE conducts exploration activities in the Gulf of Mexico. As of August 22, 2008, Contango, through its wholly-owned subsidiaries, COI and CRC, and its partially-owned subsidiaries, REX and COE, had an interest in 67 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.
 
As of June 30, 2008, Contango owned a 32.3% equity interest in REX and a 65.6% equity interest in COE, both 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 focus 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 and COE.
 
Republic Exploration LLC (REX)
 
Effective April 1, 2008, the Company sold a portion of its ownership interest in REX to an existing member of REX for approximately $0.8 million. As a result of the sale, the Company’s equity ownership interest in REX has decreased to 32.3%.
 
On April 3, 2008, the members of REX entered into an Amended and Restated Limited Liability Company Agreement (the “REX LLC Agreement”), effective as of April 1, 2008, to, among other things, distribute REX’s interest in Dutch and Mary Rose to the individual members of REX or their designees. In connection with this distribution, REX repaid in full all amounts owing by REX to a private investment firm under a $50.0 million demand promissory note with such private investment firm (the “REX Demand Note”), and all security interests and other liens granted in favor of such private investment firm as security for the obligations under the REX Demand Note have been released and terminated. The Company’s portion of such repayment was approximately $22.5 million.
 
On March 12, 2008, the Company announced that its wildcat exploration well at High Island A198, a REX prospect, was determined to be a dry hole, at a cost of approximately $4.2 million. The well has been plugged and abandoned.
 
West Delta 36 and Eugene Island 113-B, two REX prospects, are operated by a third party. The Company depends on third-party operators for the operation and maintenance of these production platforms. On March 7, 2008, REX elected to convert its 3.67% overriding royalty interest in West Delta 36 to an undivided 25% working interest, sometimes referred to herein as “WI”. As of August 21, 2008, West Delta 36, in which REX has a 20.0% net revenue interest, sometimes referred to herein as “NRI”, was producing at a rate of approximately 9.7 million cubic feet equivalent per day (“Mmcfed”), and Eugene Island 113-B, in which REX has a 3.3% NRI, was temporarily shut-in.
 
During the past twelve months, REX has been awarded the following leases:
 
             
Date
 
Lease
 
Amount
 
Lease Sale
 
•  July 2008
  Eugene Island 56   $310,999   Central GOM Lease Sale #206
•  Jan 2008
  High Island 263   $1.75 million   Western GOM Lease Sale #204
•  Jan 2008
  High Island A38   $1.1 million   Western GOM Lease Sale #204
•  Dec 2007
  Eugene Island 11   $94,673   Central GOM Lease Sale #205


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Contango Offshore Exploration LLC (COE)
 
Effective April 1, 2008, the Company sold a portion of its ownership interest in COE to an existing member or COE for approximately $0.9 million. As a result of the sale, the Company’s equity ownership interest in COE has decreased to 65.6%.
 
Grand Isle 72 (“Liberty”), a COE prospect operated by COI, began producing in March 2007 and as of August 22, 2008 was producing at a rate of approximately 0.2 Mmcfed. COE has invested approximately $5.5 million ($3.6 million net to the Company) in drilling, completion, pipeline and production facility costs as of June 30, 2008. COE has a 50% WI and a 40% NRI in this well. As of June 30, 2008, 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. As of June 30, 2008, accrued interest thereon was $668,816.
 
Grand Isle 70, another COE prospect, was drilled by COI 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 45.1% WI before completion of the well and a 52.6% WI after completion of the well, while COI has a 3.6% WI before and after completion of the well. As of June 30, 2008, COE and COI had invested approximately $3.6 million to drill Grand Isle 70.
 
Ship Shoal 358, a COE prospect, is operated by a third party. The Company depends on third-party operators for the operation and maintenance of non-operated production platforms. As of August 12, 2008, Ship Shoal 358, in which COE has a 10.0% WI and 7.7% NRI, was producing at an 8/8ths rate of approximately 2.1 Mmcfed.
 
Contango Operators, Inc
 
COI, a wholly-owned subsidiary of the Company, was formed for the purpose of drilling exploration and development wells in the Gulf of Mexico. COI operates and acquires significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, usually under a farm-out agreement, or similar agreement, with either REX or COE. COI expects to take working interests in these prospects under the same arms-length terms offered to industry third-party participants. In exchange for acting as operator, COI will receive a 10% ground floor working interest in all future wells. COI will pay the remaining 90% working interest and carry the owner of the lease (either REX or COE) for a 10% working interest through the tanks until initial production is achieved. Following a casing point election, the lease owner (either REX or COE) shall have an option to acquire a 25% working interest from COI. COI may also operate and acquire significant working interests in offshore exploration and development opportunities under farm-in agreements with third parties.
 
COI has recently drilled a well (“Eloise #1) on State of Louisiana leases at a depth below our Mary Rose discovery. The Company, through REX and COI participation, subject to elections for certain carried interests, has an approximate 54.17% WI in this well and is responsible for approximately $12.5 million of drilling costs. COI has agreed to provide REX with a carried interest in this well through the tanks. At casing point, REX “backed-in” for an additional working interest from COI and COI’s WI was reduced to approximately 36.90%. The Company expects to invest an additional $3.8 million to complete the well.
 
Effective February 1, 2008, the Company sold COI’s overriding royalty interest in Eugene Island 113-B, Ship Shoal 358 and Grand Isle 72 to JEX for $164,400.
 
Contango Resources Company
 
CRC is a wholly-owned subsidiary of Contango formed for the sole purpose of drilling and operating exploration and development wells in our Dutch and Mary Rose leases in the Gulf of Mexico. Unlike COI, CRC will not acquire additional working interests in offshore exploration and development opportunities in the Gulf of Mexico.
 
Current Activities.
 
The Company’s financial advisor, Merrill Lynch & Co., has begun meeting with parties interested in potentially purchasing the Company’s Dutch and Mary Rose discoveries in the Gulf of Mexico. Any possible sale or restructuring is subject to mutually acceptable terms and conditions, mutually satisfactory documentation,


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the consent and approval of third parties and governmental authorities, the approval of Contango’s board of directors and, if necessary, Contango’s shareholders. If Contango obtains an acceptable proposal to acquire its Dutch and Mary Rose discoveries, the disposition would likely be structured through the sale of Contango by its shareholders, with the potential purchaser acquiring the stock of Contango Oil & Gas Company and CRC. The Company’s remaining assets would be simultaneously spun-off to our shareholders through our subsidiary, Contango Energy Company. This structure would allow Contango shareholders to maintain an interest in any future exploration efforts at our other Gulf of Mexico leases.
 
A data room for the possible sale opened in July 2008. The Company anticipates receiving proposals in September 2008. If no acceptable proposals are received, the Company will terminate the sale and restructuring process and continue to develop and operate the Dutch and Mary Rose discoveries.
 
As of August 20, 2008, our three Dutch wells were flowing at a combined 8/8ths production rate of approximately 108.8 Mmcfed (approximately 41.5 Mmcfed net to Contango). The Company has invested approximately $33.8 million to drill and complete these three Dutch wells, including pipeline and production facility costs. The three Dutch wells flow to a third-party owned and operated production platform at Eugene Island 24. This platform has a capacity of 100 million cubic feet per day (“Mmcfd”) and 3,000 barrels of oil per day (“bopd”).
 
As of August 22, 2008, our four Mary Rose wells were flowing at a combined 8/8ths production rate of approximately 193.8 Mmcfed (approximately 71.4 Mmcfed net to Contango). The Company has invested approximately $69.1 million to drill and complete these four Mary Rose wells, including pipeline and production facility costs. The four Mary Rose wells flow into the Company’s recently completed production platform at Eugene Island 11, and through its associated pipeline into the ANR Pipeline Company facilities at Eugene Island 63. The gas is then processed on-shore near Patterson, Louisiana. The platform has been designed with a capacity of 500 Mmcfd and 6,000 bopd and the pipeline has been designed with a capacity of 330 Mmcfd and 6,000 bopd.
 
On April 3, 2008, the Company acquired additional working interests in the Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) discoveries in a like-kind exchange, using funds from the sale of its Eastern core Arkansas Fayetteville Shale properties held by a qualified intermediary. The Company purchased an additional 4.17% working interest and 3.33% net revenue interest in Dutch and an additional average 4.56% working interest and 3.33% net revenue interest in Mary Rose from three different companies for $100 million. The effective date of the transaction was January 1, 2008. On February 8, 2008, the Company purchased an additional 0.3% overriding royalty interest in the Dutch and Mary Rose discoveries for $9.0 million in a like-kind exchange, using funds from the sale of its Eastern core Arkansas Fayetteville Shale properties held by a qualified intermediary.
 
On January 3, 2008, the Company acquired an additional 8.33% working interest and 6.67% net revenue interest in Dutch and an additional average 9.11% working interest and 6.67% net revenue interest in Mary Rose from three different companies for $200 million, in a like-kind exchange, using funds from the sale of its Western core Arkansas Fayetteville Shale properties held by a qualified intermediary. The effective date of the transaction was January 1, 2008. As of August 22, 2008, the Company had a 47.05% working interest and 38.12% net revenue interest in Dutch, and an average 53.21% working interest and 37.00% net revenue interest in Mary Rose.
 
The Company’s independent third party engineer estimates the Dutch and Mary Rose discoveries to have total proved 8/8ths reserves as at June 30, 2008 of approximately 948 billion cubic feet equivalent (“Bcfe”) (366 Bcfe net to Contango). The Company has budgeted approximately $7.1 million to drill its first rate acceleration well (“Dutch #4”) in this field beginning September 2008, and may drill additional rate acceleration wells to fully exploit its Dutch and Mary Rose discoveries.
 
The Minerals Management Service (“MMS”) has implemented a rule on royalty relief for shallow water, deep shelf natural gas production from certain Gulf of Mexico leases. “Deep shelf gas” refers to natural gas produced from depths greater than 15,000 feet in waters of 200 meters or less. Royalty relief is available on the first 15 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


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deep gas wells drilled on the shelf of the Gulf of Mexico. The Company fully utilized its available MMS deep gas royalty relief in December 2007.
 
Offshore Properties
 
Producing Properties.  The following table sets forth the interests owned by Contango through CRC and its REX and COE affiliates in the Gulf of Mexico which are producing natural gas or oil as of August 22, 2008:
 
                                 
Area/Block
  WI     NRI    
Status
   
Notes
 
 
Contango Resources Company:
                               
Eugene Island 10 #1 (Dutch #1)
    47.05 %     38.1 %     Producing          
Eugene Island 10 #2 (Dutch #2)
    47.05 %     38.1 %     Producing          
Eugene Island 10 #3 (Dutch #3)
    47.05 %     38.1 %     Producing          
S-L 18640 #1 (Mary Rose #1)
    53.21 %     40.5 %     Producing          
S-L 19266 #1 (Mary Rose #2)
    53.21 %     38.7 %     Producing          
S-L 19266 #2 (Mary Rose #3)
    53.21 %     38.7 %     Producing          
S-L 18860 #1 (Mary Rose #4)
    34.58 %     25.5 %     Producing          
                                 
Republic Exploration LLC
                               
Eugene Island 113B
    0.00 %     3.3 %     Producing       Farmed out  
West Delta 36
    25.00 %     20.0 %     Producing       Farmed out  
                                 
Contango Offshore Exploration LLC:
                               
Grand Isle 72
    50.00 %     40.0 %     Producing          
Ship Shoal 358, A-3 well
    10.00 %     7.7 %     Producing          
 
Leases.  The following table sets forth the working interests and status of the leases owned by Contango through CRC and COI, and its REX and COE affiliates in the Gulf of Mexico as of August 22, 2008:
 
                                         
                Expiration
             
Area/Block
  WI     Lease Date     Date    
Status
   
Notes
 
 
Contango Resources Company:
                                       
S-L 19266 #3 (Eloise North #1)
    54.17 %     Feb-07       Feb-12       Completing          
S-L 19261
    53.21 %     Feb-07       Feb-12                  
S-L 19396
    53.21 %     Jun-07       Jun-12                  
Eugene Island 11
    53.21 %     Dec-07       (1 )                
                                         
Contango Operators, Inc.:
                                       
Grand Isle 63
    25.00 %     May-04       May-09                  
Grand Isle 73
    25.00 %     May-04       May-09                  
West Delta 43
    35.00 %     May-04       May-09       Dry Hole          
Ship Shoal 14
    37.50 %     May-06       May-11                  
Ship Shoal 25
    37.50 %     May-06       May-11                  
South Marsh Island 57
    37.50 %     May-06       May-11                  
South Marsh Island 59
    37.50 %     May-06       May-11                  
South Marsh Island 75
    37.50 %     May-06       May-11                  
South Marsh Island 282
    37.50 %     May-06       May-11                  
Grand Isle 70
    3.65 %     Jun-06       Jun-11                  
West Delta 77
    25.00 %     Jun-06       Jun-11                  
Vermilion 194
    37.50 %     Jul-06       Jul-11                  


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Table of Contents

                                         
                Expiration
             
Area/Block
  WI     Lease Date     Date    
Status
   
Notes
 
 
Republic Exploration LLC
                                       
High Island 113
    100.00 %     Oct-03       Oct-08                  
South Timbalier 191
    50.00 %     May-04       May-09                  
Vermilion 36
    100.00 %     May-04       May-09                  
Vermilion 109
    100.00 %     May-04       May-09                  
Vermilion 134
    100.00 %     May-04       May-09                  
West Cameron 179
    100.00 %     May-04       May-09                  
West Cameron 185
    100.00 %     May-04       May-09                  
West Cameron 200
    100.00 %     May-04       May-09                  
West Delta 18
    100.00 %     May-04       May-09                  
West Delta 33
    100.00 %     May-04       May-09                  
West Delta 34
    100.00 %     May-04       May-09                  
West Delta 43
    30.00 %     May-04       May-09       Dry Hole          
Ship Shoal 220
    50.00 %     Jun-04       Jun-09                  
South Timbalier 240
    50.00 %     Jun-04       Jun-09                  
West Cameron 133
    100.00 %     Jun-04       Jun-09                  
West Cameron 80
    100.00 %     Jun-04       Jun-09                  
West Cameron 167
    100.00 %     Jun-04       Jun-09                  
Eugene Island 76
    0.00 %     Jul-04       Jul-09       Depleted       Farmed out  
Vermilion 130
    100.00 %     Jul-04       Jul-09                  
West Cameron 107
    100.00 %     May-05       May-10                  
Eugene Island 168
    50.00 %     Jun-05       Jun-10                  
Vermilion 73
    0.00 %     Jul-05       Jul-10       Dry Hole       Farmed out  
High Island A243
    75.00 %     Jan-06       Jan-11                  
South Marsh Island 57
    50.00 %     May-06       May-11                  
South Marsh Island 59
    50.00 %     May-06       May-11                  
South Marsh Island 75
    50.00 %     May-06       May-11                  
                                         
Republic Exploration LLC (continued)
                                       
South Marsh Island 282
    50.00 %     May-06       May-11                  
Ship Shoal 14
    50.00 %     May-06       May-11                  
Ship Shoal 25
    50.00 %     May-06       May-11                  
West Delta 77
    50.00 %     Jun-06       Jun-11                  
Vermilion 154
    (2 )     Jul-06       Jul-11       (3 )     Farmed out  
Vermilion 194
    50.00 %     Jul-06       Jul-11                  
High Island A196
    100.00 %     Nov-06       Nov-11                  
High Island A197
    100.00 %     Nov-06       Nov-11                  
High Island A198
    100.00 %     Nov-06       Nov-11       Dry Hole          
High Island 263
    100.00 %     Jan-08       Jan-13                  
High Island A38
    100.00 %     Jan-08       Jan-13                  
Eugene Island 56
    100.00 %     Jul-08       Jul-13                  

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                Expiration
             
Area/Block
  WI     Lease Date     Date    
Status
   
Notes
 
 
Contango Offshore Exploration LLC:
                                       
East Breaks 283
    100.00 %     Dec-03       Dec-11                  
East Breaks 369
    0.00 %     Dec-03       Dec-08       Dry Hole       Farmed out  
East Breaks 370
    0.00 %     Dec-03       Dec-08       (4 )     Farmed out  
High Island A16
    100.00 %     Dec-03       Dec-08                  
South Timbalier 191
    50.00 %     May-04       May-09                  
Grand Isle 63
    50.00 %     May-04       May-09                  
Grand Isle 73
    50.00 %     May-04       May-09                  
Ship Shoal 220
    50.00 %     Jun-04       Jun-09                  
South Timbalier 240
    50.00 %     Jun-04       Jun-09                  
Viosca Knoll 118
    50.00 %     Jun-04       Jun-09                  
Vermilion 154
    (2 )     Jul-04       Jul-09       (3 )     Farmed out  
Viosca Knoll 475
    100.00 %     May-05       May-10                  
Eugene Island 168
    50.00 %     Jun-05       Jun-10                  
East Breaks 366
    100.00 %     Nov-05       Nov-15                  
East Breaks 410
    100.00 %     Nov-05       Nov-15                  
East Breaks 167
    75.00 %     Dec-05       Dec-10                  
High Island A311
    75.00 %     Dec-05       Dec-10                  
East Breaks 166
    75.00 %     Jan-06       Jan-11                  
High Island A342
    75.00 %     Jan-06       Jan-11                  
Ship Shoal 263
    75.00 %     Jan-06       Jan-11                  
Viosca Knoll 383
    100.00 %     Jan-06       Jan-11                  
Grand Isle 70
    45.10 %     Jun-06       Jun-11                  
Viosca Knoll 119
    50.00 %     Jun-06       Jun-11                  
 
 
(1) Held by Right-of-Use-and-Easement
 
(2) REX and COE will split a 25% back-in WI after payout
 
(3) Drilling expected by Summer 2008
 
(4) No drilling date determined yet. 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.
 
Contango Venture Capital Corporation
 
In March 2008, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, sold its direct and indirect investments in Gridpoint, Inc., Trulite, Inc., Protonex Technology Corporation, Jadoo Power Systems, Contango Capital Partners Fund, L.P. and Contango Capital Partnership Management, LLC for $3.4 million, in the aggregate, recognizing a loss of approximately $2.9 million for the fiscal year ended June 30, 2008. CVCC’s only remaining alternative energy investment is Moblize, Inc. (“Moblize”).
 
The Company originally invested $1.2 million in Moblize in exchange for 648,648 shares of Moblize convertible preferred stock. In March 2008, the Company determined that Moblize was partially impaired, and wrote down the investment to $0.6 million, recognizing a loss of $0.6 million for fiscal year ended June 30, 2008. In June 2008, CVCC sold 205,000 shares of convertible preferred stock of Moblize to a third party for $410,000. As of August 22, 2008, CVCC owned 443,648 shares of Moblize convertible preferred stock, valued at $0.2 million, which represents an approximate 19.5% ownership interest. Moblize develops real time diagnostics and field optimization solutions for the oil and gas and other industries using open-standards based technologies.

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Property Sales and Discontinued Operations
 
Freeport LNG Development, L.P.
 
On February 5, 2008, the Company sold its ten percent (10%) limited partnership interest in Freeport LNG Development L.P. (“Freeport LNG”) to Turbo LNG LLC, an affiliate of Osaka Gas Co., Ltd., for $68.0 million, and recognized a gain of approximately $63.4 million on the sale. Freeport LNG is a limited partnership formed to develop, construct and operate a 1.75 billion cubic feet per day (“Bcfd”) liquefied natural gas (“LNG”) receiving and gasification terminal on Quintana Island, near Freeport, Texas.
 
The Company used $20.3 million of the proceeds from the sale to pay off its debt with The Royal Bank of Scotland plc, including principal, interest and fees. Another $20.0 million was used to pay off its debt with a private investment firm. The remaining $27.7 million was used for working capital purposes.
 
Arkansas Fayetteville Shale
 
On December 21, 2007, the Company sold its Western core Arkansas Fayetteville Shale properties to Petrohawk Energy Corporation for $199.2 million. The sale was effective October 1, 2007. The Company sold approximately 14,200 acres with 6.4 Mmcfd of production, net to Contango. The Company recognized a gain of approximately $155.9 million for the fiscal year ended June 30, 2008 as a result of this sale.
 
On January 30, 2008, the Company sold its Eastern core Arkansas Fayetteville Shale properties to XTO Energy, Inc. for approximately $128.0 million. The sale was effective December 1, 2007. The Eastern core consisted of approximately 11,200 acres with 3.0 Mmcfd of production, net to Contango. The Company recognized a gain of approximately $106.4 million for the fiscal year ended June 30, 2008 as a result of this sale.
 
Texas and Louisana
 
Effective February 1, 2008, the Company sold its interest in two on-shore wells to Alta Resources LLC. The Alta-Ellis #1 in Texas and the Temple-Inland in Louisiana were sold for approximately $1.1 million.
 
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. The Company has a policy not to hedge its natural gas and oil production.
 
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


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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.
 
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.


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Other Laws and Regulations.  Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company’s properties and to limit the allowable production from the successful wells completed on the Company’s properties, thereby limiting the Company’s revenues.
 
The MMS administers the natural gas and oil leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The MMS holds a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the MMS changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater extent than other similarly situated producers. At the end of lease operations, oil and gas lessees must plug and abandon wells, remove platforms and other facilities, and clear the lease site sea floor. The MMS requires companies operating on the Outer Continental Shelf to obtain surety bonds to ensure performance of these obligations. Prior to the Company’s decision to act as the operator in the drilling of offshore prospects, the Company was required by the MMS to obtain surety bonds, typically providing $50,000 in coverage per lease, an amount of coverage that ensures a minimum level of performance. As an operator, however, the Company is required to obtain surety bonds of $200,000 per lease for exploration and $500,000 per lease for developmental activities.
 
The Federal Energy Regulatory Commission (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.
 
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 JEX 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.


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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
    63     Chairman, President, Chief Executive Officer, Chief Financial Officer, Secretary and Director
Lesia Bautina
    37     Senior Vice President and Controller
Sergio Castro
    38     Vice President and Treasurer
Marc Duncan
    55     President & Chief Operating Officer, Contango Operators, Inc.
B.A. Berilgen
    60     Director
Jay D. Brehmer
    43     Director
Charles M. Reimer
    63     Director
Steven L. Schoonover
    63     Director
Darrell W. Williams
    65     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.
 
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 38 year career. Currently, he is Chief Executive Officer of Patara Oil & Gas LLC. Prior to that he was Chairman, Chief Executive Officer and President of Rosetta Resources Inc., a company he founded in 2005. Mr. Berilgen was also previously the 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


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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 currently a founding partner of Southplace LLC, a provider of private-company middle-market corporate finance advisory services. Prior to that, he was 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 was most recently Chief Executive Officer of Cellxion, L.L.C., a company specializing in construction and installation of telecommunication buildings and towers, as well as the installation of high-tech telecommunication equipment. From 1990 until its sale in November 1997 to Telephone Data Systems, Inc., Mr. Schoonover served as President of Blue Ridge Cellular, Inc., a full-service cellular telephone company he co-founded. From 1983 to 1996, he served in various positions, including President and Chief Executive Officer, with Fibrebond Corporation, a construction firm involved in cellular telecommunications buildings, site development and tower construction. Mr. Schoonover has been awarded, on two occasions with two different companies, Entrepreneur of the Year, sponsored by Ernst & Young, Inc Magazine and USA Today.
 
Darrell W. Williams.  Mr. Williams has been a director of Contango since 1999. From 2005 through 2007, Mr. Williams was President and Chief Executive Officer of Porta-Kamp International LP, which specializes in the manufacture, supply and construction of remote area housing, and Chief Executive Officer 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. Each outside director of the Company receives a quarterly retainer of $8,000 payable in cash and $36,000 payable annually 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.


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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 a substantial or extended decline in natural gas and oil prices would adversely affect our revenues, profitability and growth and could have a material adverse effect on the business, the results of operations and financial condition of the Company.
 
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. We do not expect to hedge our production to protect against price decreases. 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.
 
  •  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.
 
A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our access to capital and the quantities of natural gas and oil that may be economically produced by us. A significant decrease in price levels for an extended period would negatively affect us.


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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 JEX and could be seriously harmed if JEX terminated its services with us or became otherwise unavailable.
 
Because we have only six employees, none of whom are geoscientists or petroleum engineers, we are dependent upon JEX for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. We do not have a written agreement with JEX which contractually obligates them to provide us with their services in the future. Highly qualified explorationists and engineers are difficult to attract and retain. As a result, the loss of the services of JEX could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, the loss by JEX 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, additional financing may not be available to us on acceptable terms, if at all. 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.
 
It is difficult to quantify the amount of financing we may need to fund our planned growth. The amount of funding we may need in the future depends on various factors such as:
 
  •  Our financial condition;
 
  •  The prevailing market price of natural gas and oil;
 
  •  The type of projects in which we are engaging; and
 
  •  Lead time required to bring discoveries to production.
 
We frequently obtain capital through the sale of our producing properties.
 
The Company, since its inception in September 1999, has raised approximately $484.0 million from various 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.
 
COI and CRC are wholly-owned subsidiaries of the Company, formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. COI is currently the operator of Eloise #1 and Grand Isle 72, and CRC is currently the operator for our Dutch and Mary Rose discoveries.


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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. Drilling costs could be significantly higher if we encounter difficulty in drilling offshore exploration wells. 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 new wells may not be productive or we may not recover all or any 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.
 
Additionally, we use turnkey contracts that cost more, and under certain conditions, the turnkey contract can be terminated by the turnkey drilling contractor, leading to higher risks and costs for the Company.
 
We rely on third-party operators to operate and maintain some of our production pipelines and processing facilities and as a result we have limited control over the operations of such facilities and the interests of an operator may even differ from our interests.
 
We depend upon the services of third-party operators to operate production platforms, pipelines, gas processing facilities and the infrastructure required to produce and market our natural gas, condensate and oil. We have limited influence over the conduct of operations by third-party operators. As a result, we have little control over how frequently and how long our production is shut-in when production problems, weather and other production shut-ins occur. Poor performance on the part of, or errors or accidents attributable to, the operator of a project in which we participate may have an adverse effect on our results of operations and financial condition. Also, the interest of an operator may differ from our interests.
 
Repeated production shut-ins can possibly damage our well bores.
 
Our Dutch and Mary Rose 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 may 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.
 
Concentrating our capital investment in the Gulf of Mexico increases our exposure to risk.
 
Our capital investments are focused in offshore Gulf of Mexico prospects. However, our exploration prospects in the Gulf of Mexico may not lead to significant revenues. Furthermore, we may not be able to drill productive wells at profitable finding and development costs.
 
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


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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 and may prove to be incorrect over time. As a result, our estimates may require substantial upward or downward revisions if subsequent drilling, testing and production reveal different results. Furthermore, some of the producing wells included in our reserve report have produced 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. Any downward adjustment could indicate lower future production and thus adversely affect our financial condition, future prospects and market value.
 
You should not assume that the pre-tax net present value of our proved reserves prepared in accordance with Securities and Exchange Commission 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 Company’s revenue activities are significantly concentrated in one field.
 
The proved reserves assigned to our Dutch and Mary Rose discoveries have seven producing well bores concentrated in one reservoir. As of August 29, 2008, this reservoir had only nineteen months of production history, and was producing via two pipelines and two production platforms. Reserve assessments based on only seven well bores in one reservoir with relatively limited production history are subject to greater risk of downward revision than multiple well bores from several mature producing reservoirs.
 
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.


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Exploration is a high risk activity, and our participation in drilling activities may not be successful.
 
Our future success largely depends 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.
 
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.


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  •  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, processing plants, and offshore platforms. Transportation capacity on gathering system 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 may not have title to our leased interests and if any lease is later rendered invalid, we may not be able to proceed with our exploration and development of the lease site.
 
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 JEX and others 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. However, such deficiencies may not have been cured by the


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operator of 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 many 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 depends 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 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 may from time to time drill, complete and 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.


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We are highly dependent on our management team, JEX, exploration partners and third-party consultants and any failure to retain the services of such parties could adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies.
 
The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business strategy is highly dependent on our management team, as well as certain key geoscientists, geologists, engineers and other professionals engaged by us. We are highly dependent on the services provided by JEX and we do not have any written agreements contractually obligating them to provide us with their services in the future. The loss of key members of our management team, JEX or other highly qualified technical professionals could adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies which may have a material adverse effect on our business, financial condition and operating results.
 
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 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.


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  •  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 16.8 million shares of common stock outstanding, held by approximately 92 holders of record. Directors and officers own or have voting control over approximately 3.4 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.   Properties
 
Production, Prices and Operating Expenses
 
The following table presents information from continuing operations 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,  
    2008     2007     2006  
 
Production:
                       
Natural gas (million cubic feet)
    9,089       1,792       72  
Oil and condensate (thousand barrels)
    185       34       4  
Natural gas liquids (thousand gallons)
    4,700       187        
                         
Total (million cubic feet equivalent)
    10,870       2,023       96  
Natural gas (thousand cubic feet per day)
    24,833       4,910       197  
Oil and condensate (barrels per day)
    505       93       11  
Natural gas liquids (gallons per day)
    12,842       512        
                         
Total (thousand cubic feet equivalent per day)
    29,698       5,541       263  
Average sales price:
                       
Natural gas (per thousand cubic feet)
  $ 9.81     $ 6.62     $ 7.05  
Oil and condensate (per barrel)
  $ 108.36     $ 59.60     $ 61.53  
Natural gas liquids (per gallon)
  $ 1.55     $ 0.94     $  
Total (per thousand cubic feet equivalent)
  $ 10.72     $ 6.91     $ 8.08  
Selected data per Mcfe:
                       
Total lease operating expenses
  $ 0.62     $ 0.44     $ (0.03 )
General and administrative expenses
  $ 1.51     $ 3.38     $ 48.44  
Depreciation, depletion and amortization of natural gas and oil properties
  $ 1.01     $ 0.61     $  


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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,  
    2008     2007     2006  
 
Property acquisition costs:
                       
Unproved
  $     $ 3,571,830     $ 14,609,232  
Proved
    309,000,000              
Exploration costs
    45,243,651       72,888,603       19,529,607  
Developmental costs
    76,025,586       1,453,066       590,395  
Capitalized interest
          1,083,693       149,365  
                         
Total costs
  $ 430,269,237     $ 78,997,192     $ 34,878,599  
                         
 
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,  
    2008     2007     2006  
    Gross     Net     Gross     Net     Gross     Net  
 
Exploratory Wells:
                                               
Productive (onshore)
    34       2.2       60       9.9       11       2.0  
Productive (offshore)
    4       2.0       4       1.6       1       0.6  
Non-productive (onshore)
    19       3.9       4       0.6       3       2.8  
Non-productive (offshore)
    1       1.0       1       0.4       2       0.9  
                                                 
Total
    58       9.1       69       12.5       17       6.3  
                                                 
 
The productive and non-productive onshore wells listed above relate strictly to our investment in the Arkansas Fayetteville Shale. At the time the Company sold its interest in the Arkansas Fayetteville Shale wells, the Company had 16 wells that were being drilled. We have classified those 16 wells as non-productive.
 
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, 2008:
 
                                 
    Developed
    Undeveloped
 
    Acreage(1)(2)     Acreage(1)(3)  
    Gross(4)     Net(5)     Gross(4)     Net(5)  
 
Onshore Texas
                5,800       4,060  
Offshore Gulf of Mexico
    21,950       5,920       237,029       104,442  
                                 
Total
    21,950       5,920       242,829       108,502  
                                 
 
 
(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.


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(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).
 
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 32.3% interest in Republic Exploration LLC’s 1,163 net developed acres and 121,685 net undeveloped acres, and (ii) our 65.6% interest in Contango Offshore Exploration LLC’s 3,000 net developed acres and 75,476 net undeveloped acres. In addition, the Company holds royalty interests in approximately 10,760 gross undeveloped acres (484 net undeveloped acres) and 5,000 gross developed acres (71 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, 2008:
 
                 
    Total Productive
 
    Wells(1)  
    Gross(2)     Net(3)  
 
Natural gas (offshore)
    11       3.8  
Oil
           
                 
Total
    11       3.8  
                 
 
 
(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.
 
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, 2008, based on a reserve report generated by William M. Cobb & Associates, Inc. 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, 2008 was based on $13.095 per million British thermal units (“MMbtu”) for natural gas at the NYMEX and $140.00 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, 2008  
Offshore
  Producing     Non-Producing     Total  
 
Natural gas (MMcf)
    262,502       29,066       291,568  
Oil and condensate (MBbls)
    5,161       318       5,479  
Natural gas liquids (MBbls)
    6,759       680       7,439  
Total proved reserves (MMcfe)
    334,022       35,054       369,076  
Pre-tax net present value ($000) (Disc. @ 10%)
  $ 2,983,433     $ 200,410       3,183,843  
 
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


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third party engineers must project production rates, estimate timing and amount of development expenditures, analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of all of this data can vary. Therefore, estimates of natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from estimates. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
 
It should not be assumed that the pre-tax net present value is the current market value of our estimated natural gas and oil reserves. In accordance with requirements of the Securities and Exchange Commission, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.
 
Item 3.   Legal Proceedings
 
As of the date of this Form 10-K, we are not a party to any material legal proceedings and we are not aware of any material proceedings contemplated against us.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
During the quarter ended June 30, 2008, no matters were submitted to a vote of security holders.
 
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 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  
Fiscal Year 2008:
               
Quarter ended September 30, 2007
  $ 40.20     $ 32.05  
Quarter ended December 31, 2007
  $ 52.70     $ 36.75  
Quarter ended March 31, 2008
  $ 69.15     $ 49.52  
Quarter ended June 30, 2008
  $ 94.40     $ 69.25  
 
On August 22, 2008, the closing price of our common stock on the American Stock Exchange was $77.98 per share, and there were approximately 16.8 million shares of Contango common stock outstanding, held by approximately 92 holders of record.
 
We have not declared or paid any dividends on our shares of 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 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 was convertible at any time by the holder into shares of our common stock at a price of $38.00 per share. The


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dividend on the Series E preferred stock was paid quarterly in cash at a rate of 6.0% per 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.
 
During the quarter ended March 31, 2008, four Series E preferred stockholders voluntarily elected to convert a total of 2,400 shares of Series E preferred stock to 315,786 shares of our common stock. The converted shares of Series E preferred stock had a face value of $12.0 million. During the quarter ended June 30, 2008, the final three Series E preferred stockholders voluntarily elected to convert a total of 3,600 shares of Series E preferred stock to 473,682 shares of our common stock. The converted shares of Series E preferred stock had a face value of $18.0 million.
 
The following table sets forth information about our equity compensation plan at June 30, 2008:
 
                         
    Number of Securities to be
  Weighted-Average
  Number of Securities Remaining
    Issued upon Exercise of
  Exercise Price of
  Available for Future Issuance
    Outstanding options,
  Outstanding Options,
  Under Equity Compensation
Plan Category
  Warrants and Rights   Warrants and Rights   Plans
 
1999 Stock Incentive Plan
    855,667     $ 11.57       568,666  
 
On February 13, 2008, the Company’s board of directors approved the purchase of an aggregate of 99,333 stock options from three officers of the Company and one member of its board of directors for approximately $5.9 million, in the aggregate. The board also approved the purchase of 10,000 shares of common stock from one member of its board of directors for approximately $0.7 million. All purchases were completed during the three months ended March 31, 2008. The Company does not have a program to repurchase shares of our common stock.


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The following graph compares the yearly percentage change from June 30, 2003 until June 30, 2008 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, 2003 and that all dividends were reinvested. The stock performance for our common stock is not necessarily indicative of future performance.
 
Comparison of Fiscal Year 2008 Cumulative Total Return
 
(LINE CHART)
 
                                                             
      06/30/03     06/30/04     06/30/05     6/30/2006     6/30/2007     6/30/2008
Peer Group Composite
      100         199         280         405         449         808  
Russell 2000 Stock Index
      100         132         143         162         186         154  
Contango Oil & Gas Co. 
      100         163         225         346         887         2,272  
                                                             


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Item 6.   Selected Financial Data
 
                                         
    Year Ended June 30,  
    2008     2007     2006     2005     2004  
    (Dollar amounts in 000s, except per share amounts)  
 
Financial Data:
                                       
Revenues:
                                       
Natural gas and oil sales
  $ 116,498     $ 14,140     $ 776     $ 1,051     $ 28  
Gain from hedging activities
                            58  
                                         
Total revenues
  $ 116,498     $ 14,140     $ 776     $ 1,051     $ 86  
                                         
Income (loss) from continuing operations
  $ 83,221     $ (1,078 )   $ (6,888 )   $ (3,191 )   $ (340 )
Discontinued operations, net of income taxes
    173,685       (1,617 )     6,681       15,609       8,040  
                                         
Net income (loss)
  $ 256,906     $ (2,695 )   $ (207 )   $ 12,418     $ 7,700  
Preferred stock dividends
    1,548       540       601       420       620  
                                         
Net income (loss) attributable to common stock
  $ 255,358     $ (3,235 )   $ (808 )   $ 11,998     $ 7,080  
                                         
Net income (loss) per share:
                                       
Basic
                                       
Continuing operations
  $ 5.05     $ (0.03 )   $ (0.50 )   $ (0.27 )   $ (0.09 )
Discontinued operations
    10.73       (0.18 )     0.45       1.19       0.77  
                                         
Total
  $ 15.78     $ (0.21 )   $ (0.05 )   $ 0.92     $ 0.68  
                                         
Diluted
                                       
Continuing operations
  $ 4.82     $ (0.03 )   $ (0.50 )   $ (0.27 )   $ (0.09 )
Discontinued operations
    10.06       (0.18 )     0.45       1.19       0.77  
                                         
Total
  $ 14.88     $ (0.21 )   $ (0.05 )   $ 0.92     $ 0.68  
                                         
Weighted average shares outstanding:
                                       
Basic
    16,185       15,430       14,760       13,089       10,484  
Diluted
    17,263       15,430       14,760       13,089       10,484  
Working capital (deficit)
    29,913     $ (4,088 )   $ 18,333     $ 28,839     $ 3,032  
Capital expenditures
  $ 430,269     $ 78,997     $ 34,879     $ 9,677     $ 12,384  
Long term debt
  $ 15,000     $ 20,000     $ 10,000     $     $ 7,089  
Stockholders’ equity
  $ 341,998     $ 90,804     $ 62,540     $ 50,979     $ 36,117  
Total assets
  $ 599,974     $ 153,936     $ 89,385     $ 53,353     $ 45,511  
Proved Reserve Data:
                                       
Total proved reserves (Mmcfe)
    369,076       84,876       3,430       1,373       17,422  
Pre-tax net present value (SEC at 10%)
  $ 3,183,843     $ 329,179     $ 8,852     $ 7,081     $ 59,767  


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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 business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico. COI and CRC, our wholly-owned subsidiaries, act as operator on certain offshore prospects.
 
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. 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 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 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 14 for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations.


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Results of Operations
 
The following is a discussion of the results of our continuing operations for the fiscal year ended June 30, 2008, compared to the fiscal year ended June 30, 2007, and for the fiscal year ended June 30, 2007, compared to the fiscal year ended June 30, 2006.
 
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 geologic declines.
 
The table below sets forth revenue and production data for continuing operations for the fiscal years ended June 30, 2008, 2007 and 2006.
 
                                                 
    Year Ended June 30,           Year Ended June 30,        
    2008     2007     %     2007     2006     %  
    ($000)           ($000)        
 
Revenues:
                                               
Natural gas and oil sales
  $ 116,498     $ 14,140       724 %   $ 14,140     $ 776       1722 %
                                                 
Total revenues
  $ 116,498     $ 14,140             $ 14,140     $ 776          
Production:
                                               
Natural gas (million cubic feet)
    9,089       1,792       407 %     1,792       72       2389 %
Oil and condensate (thousand barrels)
    185       34       444 %     34       4       750 %
Natural gas liquids (thousand gallons)
    4,700       187       2413 %     187             100 %
                                                 
Total (million cubic feet equivalent)
    10,870       2,023       437 %     2,023       96       2007 %
Natural gas (thousand cubic feet per day)
    24,833       4,910       406 %     4,910       197       2389 %
Oil and condensate (barrels per day)
    505       93       443 %     93       11       750 %
Natural gas liquids (gallons per day)
    12,842       512       2407 %     512             100 %
                                                 
Total (thousand cubic feet per day equivalent)
    29,698       5,541       436 %     5,541       263       2007 %
Average Sales Price:
                                               
Natural gas (per thousand cubic feet)
  $ 9.81     $ 6.62       48 %   $ 6.62     $ 7.05       (6 )%
Oil and condensate (per barrel)
  $ 108.36     $ 59.60       82 %   $ 59.60     $ 61.53       (3 )%
Natural gas liquids (per gallon)
  $ 1.55     $ 0.94       65 %   $ 0.94     $       100 %
Operating expenses
  $ 6,777     $ 891       661 %   $ 891     $ (3 )     29800 %
Exploration expenses
  $ 5,729     $ 2,380       141 %   $ 2,380     $ 6,816       (65 )%
Depreciation, depletion and amortization
  $ 11,900     $ 1,607       641 %   $ 1,607     $ 202       696 %
Impairment of natural gas and oil properties
  $ 642     $       100 %   $     $ 708       (100 )%
General and administrative expenses
  $ 16,929     $ 6,842       147 %   $ 6,842     $ 4,761       44 %
Interest expense, net of interest capitalized
  $ 3,933     $ 2,163       82 %   $ 2,163     $ 54       3906 %
Interest income
  $ 1,969     $ 886       122 %   $ 886     $ 826       7 %
Gain (loss) on sale of assets and other
  $ 62,314     $ (2,684 )     2422 %   $ (2,684 )   $ 250       (1174 )%
 
Natural Gas and Oil Sales.  We reported natural gas and oil sales of approximately $116.5 million for the year ended June 30, 2008, up from approximately $14.1 million reported for the year ended June 30, 2007. This increase is attributable to our Dutch #2 discovery which began producing in July 2007, our Dutch #3 discovery which began producing in November 2007, our Mary Rose #1 and #3 discoveries which began producing in April 2008, and our Mary Rose #2 discovery which began producing in June 2008. Another reason for the large increase is the additional interest we purchased in our Dutch and Mary Rose discoveries, effective January 1, 2008.


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We reported natural gas and oil sales of approximately $14.1 million for the year ended June 30, 2007, up from approximately $0.8 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 and our Liberty discovery which began producing in March 2007.
 
Natural Gas and Oil Production and Average Sales Prices.  Our net natural gas production for the year ended June 30, 2008 was approximately 24.8 Mmcfd, up from approximately 4.9 Mmcfd for the year ended June 30, 2007. Net oil production for the period was up from 93 bopd to 505 bopd, and NGL production was up from 512 gallons per day to 12,842 gallons per day for the same period. The increase in natural gas, oil and NGL production was the result of our Dutch #2 discovery which began producing in July 2007, our Dutch #3 discovery which began producing in November 2007, our Mary Rose #1 and #3 discoveries which began producing in April 2008, and our Mary Rose #2 discovery which began producing in June 2008. Another reason for the large increase is the additional interest we purchased in our Dutch and Mary Rose discoveries, effective January 1, 2008. For the year ended June 30, 2008, the price of natural gas was $9.81 per Mcf while the price for oil and NGLs was $108.36 per barrel and $1.55 per gallon, respectively. For the year ended June 30, 2007, the price of natural gas was $6.62 per Mcf while the price for oil and NGLs was $59.60 per barrel and $0.94 per gallon, respectively.
 
Our net natural gas production for the year ended June 30, 2007 was approximately 4.9 Mmcfd, up from approximately 0.2 Mmcfd for the year ended June 30, 2006. Net oil production for the period was up from 11 bopd to 93 bopd, and NGL production increased from zero to 512 gallons per day for the same period. The increase in natural gas, oil and NGL production was primarily the result of our Dutch #1 discovery which began producing in January 2007 and our Liberty discovery which began producing in March 2007. For the year ended June 30, 2007, the price of natural gas was $6.62 per Mcf while the price for oil and NGLs was $59.60 per barrel and $0.94 per gallon, respectively. For the year ended June 30, 2006, the price of natural gas was $7.05 per Mcf while the price for oil was $61.53 per barrel.
 
Operating Expenses.  Operating expenses for the year ended June 30, 2008 were approximately $6.8 million which related mainly to continuing operations from our three Dutch wells and our first three Mary Rose wells, compared to operating expenses for the year ended June 30, 2007 of approximately $0.9 million which related mainly to only one Dutch well. Operating expenses for the year ended June 30, 2006 were immaterial due to no significant producing discoveries during this time.
 
Exploration Expense.  We reported approximately $5.7 million of exploration expenses for the year ended June 30, 2008. Of this amount, approximately $4.2 million was related to the dry hole the Company drilled at High Island A198, approximately $0.6 million was attributable to the cost to acquire and reprocess 3-D seismic data offshore in the Gulf of Mexico, and approximately $0.9 million was attributable to the payment of delay rentals.
 
We reported approximately $2.4 million of exploration expenses for the year ended June 30, 2007. Of this amount, approximately $1.4 million was attributable to the cost to acquire and reprocess 3-D seismic data in the Gulf of Mexico, and approximately $1.0 million was attributable to the payment of delay rentals.
 
We reported approximately $6.8 million of exploration expenses for the year ended June 30, 2006. Of this amount, approximately $5.9 million was related to unsuccessful wells drilled in the Gulf of Mexico during the period, approximately $0.3 million was attributable to the cost to acquire and reprocess 3-D seismic data offshore in the Gulf of Mexico, and approximately $0.6 million was attributable to the cost of delay rentals.
 
Depreciation, Depletion and Amortization.  Depreciation, depletion and amortization for the year ended June 30, 2008 was approximately $11.9 million. For the year ended June 30, 2007, we recorded approximately $1.6 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 #2, Dutch #3, Mary Rose #1, Mary Rose #2 and Mary Rose #3 discoveries, as well as from the additional interest we purchased in our Dutch and Mary Rose discoveries, effective January 1, 2008.
 
Depreciation, depletion and amortization for the year ended June 30, 2007 was approximately $1.6 million. For the year ended June 30, 2006, we recorded approximately $0.2 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 and Liberty discoveries.


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Impairment of Natural Gas and Oil Properties.  We reported an impairment of natural gas and oil properties of approximately $0.6 million for the year ended June 30, 2008, related to the expiration of Eugene Island 209 and Viosca Knoll 161, two leases held by COE. The Company did not report an impairment charge for the fiscal year ended June 30, 2007.
 
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.
 
General and Administrative Expenses.  General and administrative expenses for the year ended June 30, 2008 were approximately $16.9 million, up from $6.8 million for the year ended June 30, 2007. Major components of general and administrative expenses for the year ended June 30, 2008 included approximately $1.0 million in salaries, $12.1 million in benefits and bonuses (includes $1.2 million in non-cash expenses related to the cost of expensing stock options), $1.1 million in office administration and other expenses, $0.4 million in insurance costs, $0.9 million in accounting and tax services, and $1.4 million in legal and other 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.
 
General and administrative expenses for the year ended June 30, 2006 were approximately $4.8 million. 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.
 
Interest Expense.  Interest expense for the fiscal years ended June 30, 2008, 2007 and 2006 were approximately $3.9 million, $2.2 million, and $54,488, respectively. The higher levels of interest expense for fiscal year 2007 and 2008 were attributable to higher levels of bank debt outstanding during such period. The lower level of interest expense in fiscal year 2006 was attributable to the Company retiring all of its long term debt in the second quarter of fiscal year 2005. No interest was capitalized for unevaluated property for the fiscal year ended June 30, 2008.
 
Interest Income.  Interest income for the fiscal years ended June 30, 2008, 2007 and 2006 were approximately $1.9 million, $0.9 million, and $0.8 million, respectively. The higher levels of interest income for fiscal years 2008 and 2007 were attributable to loans made to related parties and interest earned on the proceeds from our various property sales.
 
Gain on Sale of Assets and Other.  We reported a gain on sale of assets and other of approximately $62.3 million for the year ended June 30, 2008. Of this amount, approximately $63.4 million relates to the gain on the sale of the Company’s 10% limited partnership interest in Freeport LNG, $2.1 relates to a payment from a stockholder related to a short swing profit liability, $0.3 million relates to the gain on the sale of certain overriding royalty interests and onshore properties, offset by a $2.9 million loss recognized on the sale of certain assets held by CVCC and a $0.6 million loss attributable to the write-down of the Company’s investment in Moblize.
 
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.
 
Discontinued Operations  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


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which generated 7.7%, 24.3% and 86.6% of combined revenues for the fiscal years ended June 30, 2008, 2007 and 2006, respectively. Please see Note 5 — 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
 
Cash From Operating Activities.  Cash flow from operating activities provided approximately $112.7 million in cash for the year ended June 30, 2008 compared to $4.1 million for the same period in 2007. This increase in cash provided by operating activities is attributable to increased natural gas and oil sales from our Dutch #2, Dutch #3, Mary Rose #1, Mary Rose #2 and Mary Rose #3 discoveries which began producing during the year ended June 30, 2008. Another reason for the increase is the added sales attributable to the additional interest we purchased in our Dutch and Mary Rose discoveries, effective January 1, 2008.
 
Cash flow from operating activities provided approximately $4.1 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 for the year ended June 30, 2007.
 
Cash From Investing Activities.  Cash flows used in investing activities for the year ended June 30, 2008 were approximately $38.9 million, compared to $55.1 million used in investing activities for the year ended June 30, 2007. This decrease in cash flows used in investing activities was due primarily to the proceeds received from the sale of our Arkansas Fayetteville Shale properties and our 10% limited partnership interest in Freeport LNG, partially offset by the acquisition of additional interests in our Dutch and Mary Rose leases.
 
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 From Financing Activities.  Cash flows used in financing activities for the year ended June 30, 2008 were approximately $20.2 million, compared to $47.0 million provided by financing activities for the same period in 2007. This decrease in cash flow is primarily attributable to $48.5 million of debt repayment by the Company and its affiliates, $1.5 million of preferred stock dividends paid, and $6.6 million of stock and options repurchased during the year ended June 30, 2008, partially offset by $35.0 million of borrowings under credit facilities.
 
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.
 
Income Taxes.  During the year ended June 30, 2008, we paid approximately $24.5 million in estimated income taxes.
 
Capital Budget.  For fiscal year 2009, our capital expenditure budget calls for us to invest a total of approximately $116.3 million. Of the $116.3 million, our budget calls for us to invest approximately $16.3 million to drill and complete Eloise #1. We have also budgeted to invest approximately $100.0 million to drill two rate acceleration wells at our Dutch and Mary Rose leases and four currently planned wildcat exploration wells in the Gulf of Mexico.
 
As of August 26, 2008, we had approximately $75.3 million in cash and cash equivalents.
 
Discontinued Operations.  The Company, since its inception in September 1999, has raised $484.0 million in proceeds from twelve 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


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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.
 
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 natural gas and oil property sales in each of the fiscal years ended June 30, 2006, 2007 and 2008, 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-29 and F-30 for a more detailed discussion regarding our standardized measure.
 
                                 
                      Standardized
 
                      Measure of
 
                      Discounted
 
                      Future Net
 
                Reserves
    Cash Flows
 
Fiscal Year of
  Proceeds
    Reserves
    at End of
    at End of
 
Property Sale
  Received     Sold (Mmcfe)     Fiscal Year (Mmcfe)     Fiscal Year  
 
2006
  $ 12,892,916       2,294       3,430     $ 7,734,106  
2007
  $ 7,000,000       426       84,876     $ 252,297,275  
2008
  $ 328,300,000       13,789       369,076     $ 2,233,918,129  
 
For fiscal year 2008, the Company realized approximately $8.1 million in operating cash flows from discontinued operations, approximately $319.0 million in investing cash flows from discontinued operations and zero in financing cash flows from discontinued operations.
 
Off Balance Sheet Arrangements
 
None.
 
Contractual Obligations
 
The following table summarizes our known contractual obligations as of June 30, 2008:
 
                                         
    Payment due by Period  
          Less Than
                More Than
 
    Total     1 Year     1-3 Years     3-5 Years     5 Years  
 
Long term debt
  $ 15,000,000     $     $ 15,000,000           $  
Operating leases
    625,182       190,458       434,724              
                                         
Total
  $ 15,625,182     $ 190,458     $ 15,434,724     $     $  
                                         
 
Additionally, once we have completed drilling Eloise #1, we are committed to retain the drilling rig for two more wells. The Company will use this rig to drill a rate acceleration well at Dutch #4 and then either a second rate acceleration well or a wildcat exploration well.
 
Credit Facility
 
On August 26, 2008, the Company prepaid the $15.0 million it had outstanding under its $30.0 million loan agreement with a private investment firm (the “Term Loan Agreement”) and terminated the Term Loan Agreement. The Company paid an additional $116,442 in accrued and unpaid interest and non-use fees. As of June 30, 2008, the Company was in compliance with its financial covenants, ratios and other provisions of the Term Loan Agreement.


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On February 5, 2008, using the proceeds from our $68.0 million sale of Freeport LNG, the Company prepaid the $20.0 million it had outstanding under its three-year $20.0 million secured term loan facility with The Royal Bank of Scotland plc (the “RBS Facility”) and terminated the RBS Facility. The Company paid an additional $342,292 in accrued and unpaid interest and prepayment fees.
 
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 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


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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, 2008 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 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 of Financial Accounting Standard (“SFAS”) 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
 
FASB Staff Position No. EITF 03-6-1 (EITF 03-6-1).  EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the two-class method described in SFAS No. 128, Earnings per Share. The provisions of EITF 03-6-1 are effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period EPS data presented shall be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform with the provisions of EITF 03-6-1. Early application is not permitted. We do not expect EITF 03-6-1 to have a material effect on our consolidated financial statements.
 
In May 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 162 (“SFAS 162”), “The Hierarchy of Generally Accepted Accounting Principles”. SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP (the GAAP hierarchy). SFAS 162 is effective 60 days following the Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendments to AU section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We are currently evaluating the provisions of SFAS 162 and assessing the impact, if any, it may have on our financial position and results of operations.
 
Effective July 1, 2009, the FASB issued SFAS No. 157-2 (“SFAS 157-2”), “Effective Date of FASB Statement No. 157”. This pronouncement defers the effective date of SFAS No. 157 (“SFAS 157”), “Fair Value Measurements” to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years, for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). An entity that has issued interim or annual financial statements reflecting the application of the measurement and disclosure provisions of SFAS 157 prior to


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February 12, 2008, must continue to apply all provisions of SFAS 157. We are currently evaluating the impact of our adoption of SFAS 157-2 on our consolidated financial statements.
 
In December 2007, the FASB issued SFAS No. 141(R) (“SFAS 141(R)”), “Business Combinations” and SFAS No. 160 (“SFAS 160”), “Noncontrolling Interests in Consolidated Financial Statements”. These statements require most identifiable assets, liabilities and noncontrolling interests to be recorded at full fair value and require noncontrolling interests to be reported as a component of equity. Both statements are effective for periods beginning on or after December 15, 2008, and earlier adoption is prohibited. SFAS 141(R) will be applied to business combinations occurring after the effective date and SFAS 160 will be applied prospectively to all noncontrolling interests, including any that arose before the effective date. We are currently evaluating the provisions of SFAS 141(R) and SFAS 160 and assessing the impact, if any, they may have on our financial position and results of operations.
 
In February 2007, the 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 and cash flows.
 
In September 2006, the FASB issued SFAS 157. 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 that SFAS 157 may have on our financial position, results of operations and 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, 2008, a 10% fluctuation in the prices received for natural gas and oil production would have had an approximate $11.7 million impact on our revenues.
 
Interest Rate Risk.  As of August 26, 2008 we have no long-term debt subject to the risk of loss associated with movements in interest rates.
 
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-30 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 Securities Exchange Act of 1934 (the “Exchange Act”)) as of June 30, 2008, the end of the period covered


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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) 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, 2008.
 
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, 2008, 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
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, 2008, 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, 2008, 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, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended June 30, 2008 and our report dated August 29, 2008 expressed an unqualified opinion on those financial statements.
 
/s/  GRANT THORNTON LLP
 
Houston, Texas
August 29, 2008


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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 2008 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, 2008.
 
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 and 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-31 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.
 
(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.


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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)
  2 .5   Asset Purchase Agreement by and among Petrohawk Energy Corporation and Contango Operators Inc. (successor-in-interest to Contango Gas Solutions, L.P.), Alta Resources, L.L.C., GPM Energy, LLC, MND Partners, L.P. and TePee Petroleum Company, Inc., dated as of November 26, 2007.(25)
  2 .6   Asset Purchase Agreement by and among XTO Energy Inc. and Contango Operators, Inc., Alta Resources, L.L.C., GPM Energy, LLC, MND Partners, L.P. and TePee Petroleum Company, Inc., dated as of January 4, 2008.(26)
  2 .7   Partnership Interest Purchase Agreement by and among Turbo LNG LLC, Contango Sundance, Inc. and Osaka Gas Co., Ltd., as Guarantor, dated January 7, 2008.(27)
  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)


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Table of Contents

         
Exhibit
   
Number
 
Description
 
  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)
  10 .27   Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008.(28)
  10 .28   Partial Assignment of Oil and Gas Leases between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008.(28)
  10 .29   Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008.(28)
  10 .30   Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of January 3, 2008.(28)
  10 .31   Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated as of January 3, 2008.(28)
  10 .32   Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of January 3, 2008.(28)

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Table of Contents

         
Exhibit
   
Number
 
Description
 
  10 .33   Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008.(28)
  10 .34   Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008.(28)
  10 .35   Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008.(28)
  10 .36   Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008.(30)
  10 .37   Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008.(30)
  10 .38   Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008.(30)
  10 .39   Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of April 3, 2008.(30)
  10 .40   Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated as of April 3, 2008. (30
  10 .41   Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of April 3, 2008.(30)
  10 .42   Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008.
  10 .43   Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008.
  10 .44   Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008.
  10 .45   Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008.
  10 .46   Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008.
  10 .47   Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008.
  10 .48   Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008.
  10 .49   Amended and Restated Limited Liability Company Agreement of Republic Exploration LLC, dated April 1, 2008.(30)
  10 .50   Amended and Restated Limited Liability Company Agreement of Contango Offshore Exploration LLC, dated April 1, 2008
  10 .51   Third Amendment to Term Loan Agreement, dated as of January 17, 2008, between Contango Oil & Gas Company, as Borrower, and Centaurus Capital LLC, as Lender.(29)
  10 .52   Fourth Amendment to Term Loan Agreement, dated as of February 13, 2008, between Contango Oil & Gas Company, as Borrower, and Centaurus Capital LLC, as Lender.(31)
  10 .53   Amended and Restated Term Loan Agreement, dated June 5, 2008, between Contango Oil & Gas Company, as Borrower, and Centaurus Capital LLC, as Lender.
  14 .1   Code of Ethics.(12)
  21 .1   List of Subsidiaries.
  21 .2   Organizational Chart.
  23 .1   Consent of William M. Cobb & Associates, Inc.
  23 .2   Consent of Grant Thornton LLP.
  23 .3   Consent of W.D. Von Gonten & Co.

42


Table of Contents

         
Exhibit
   
Number
 
Description
 
  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.
 
 
†  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.

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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.
 
25. Filed as an exhibit to the Company’s report on Form 8-K, dated November 26, 2007, as filed with the Securities and Exchange Commission on November 29, 2007.
 
26. Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2008, as filed with the Securities and Exchange Commission on January 10, 2008.
 
27. Filed as an exhibit to the Company’s report on Form 8-K, dated February 5, 2008, as filed with the Securities and Exchange Commission on February 8, 2008.
 
28. Filed as an exhibit to the Company’s report on Form 8-K, dated January 3, 2008, as filed with the Securities and Exchange Commission on January 9, 2008.
 
29. Filed as an exhibit to the Company’s report on Form 8-K, dated January 17, 2008, as filed with the Securities and Exchange Commission on January 24, 2008.
 
30. Filed as an exhibit to the Company’s report on Form 8-K, dated April 3, 2008, as filed with the Securities and Exchange Commission on April 9, 2008.
 
31. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2008, dated May 12, 2008, as filed with the Securities and Exchange Commission.


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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

Kenneth R. Peak
Chairman, Chief Executive Officer and Chief Financial Officer
(principal executive officer
and principal financial officer)
 
/s/  LESIA BAUTINA

Lesia Bautina
Senior Vice President and Controller
(principal accounting officer)
 
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

Kenneth R. Peak
  Chairman of the Board   August 29, 2008
         
/s/  B.A. BERILGEN

B.A. Berilgen
  Director   August 29, 2008
         
/s/  JAY D. BREHMER

Jay D. Brehmer
  Director   August 29, 2008
         
/s/  CHARLES M. REIMER

Charles M. Reimer
  Director   August 29, 2008
         
/s/  STEVEN L. SCHOONOVER

Steven L. Schoonover
  Director   August 29, 2008
         
/s/  DARRELL W. WILLIAMS

Darrell W. Williams
  Director   August 29, 2008


45


 

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
         
    Page
 
    F-2  
    F-3  
    F-4  
    F-5  
    F-6  
    F-7  
    F-25  
    F-28  


F-1


Table of Contents

 
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, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended June 30, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2008 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), Contango Oil & Gas Company and subsidiaries’ internal control over financial reporting as of June 30, 2008, 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 August 29, 2008 expressed an unqualified opinion on the internal control over financial reporting.
 
/s/  GRANT THORNTON LLP
 
Houston, Texas
August 29, 2008


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Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
                 
    June 30,  
    2008     2007  
 
ASSETS
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 59,884,574     $ 6,177,618  
Short-term investments
          2,200,576  
Inventory tubulars
    334,797       334,797  
Accounts receivable:
               
Trade receivable
    72,343,761       7,853,080  
Advances to affiliates
    5,754,516       5,259,191  
Joint interest billings receivable
    18,019,847       7,894,505  
Prepaid capital costs
    1,264,278       5,539,419  
Income tax receivable
          2,666,884  
Other
    1,147,345       255,788  
                 
Total current assets
    158,749,118       38,181,858  
                 
PROPERTY, PLANT AND EQUIPMENT:
               
Natural gas and oil properties, successful efforts method of accounting:
               
Proved properties
    442,630,193       82,655,848  
Unproved properties
    7,591,447       22,012,054  
Furniture and equipment
    278,737       235,512  
Accumulated depreciation, depletion and amortization
    (13,134,511 )     (3,584,618 )
                 
Total property, plant and equipment, net
    437,365,866       101,318,796  
                 
OTHER ASSETS:
               
Cash and other assets held by affiliates
    3,299,002       1,195,074  
Investment in Freeport LNG Project
          3,243,585  
Investment in Contango Venture Capital Corporation
    190,000       5,864,558  
Deferred income tax asset
          3,377,016  
Facility fees and other assets
    369,764       754,622  
                 
Total other assets
    3,858,766       14,434,855  
                 
TOTAL ASSETS
  $ 599,973,750     $ 153,935,509  
                 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
               
Accounts payable
  $ 22,990,887     $ 14,659,860  
Royalties and working interests payable
    66,606,414        
Accrued liabilities
    10,334,008       1,417,279  
Joint interest advances
    15,666,389        
Accrued exploration and development
    3,082,399       14,235,062  
Advances from affiliates
    2,965,022       3,417,103  
Debt of affiliates
    3,261,177       8,540,091  
Income tax payable
    3,463,176        
Other current liabilities
    466,232        
                 
Total current liabilities
    128,835,704       42,269,395  
                 
LONG-TERM DEBT
    15,000,000       20,000,000  
DEFERRED TAX LIABILITY
    112,189,684        
ASSET RETIREMENT OBLIGATION
    1,949,881       862,344  
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  
Common stock, $0.04 par value, 50,000,000 shares authorized, 19,404,746 shares issued and 16,819,746 outstanding at June 30, 2008, 18,539,807 shares issued and 15,964,807 outstanding at June 30, 2007,
    776,189       741,591  
Additional paid-in capital
    73,030,926       75,849,506  
Accumulated other comprehensive income
          715,659  
Treasury stock at cost (2,585,000 and 2,575,000 shares, respectively)
    (6,843,900 )     (6,180,000 )
Retained earnings
    275,035,266       19,676,774  
                 
Total shareholders’ equity
    341,998,481       90,803,770  
                 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
  $ 599,973,750     $ 153,935,509  
                 
 
The accompanying notes are an integral part of these consolidated financial statements.


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Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
                         
    Year Ended June 30,  
    2008     2007     2006  
 
REVENUES:
                       
Natural gas and oil sales
  $ 116,497,713     $ 14,140,161     $ 776,331  
                         
Total revenues
    116,497,713       14,140,161       776,331  
                         
EXPENSES:
                       
Operating expenses
    6,776,757       891,116       (3,213 )
Exploration expenses
    5,728,600       2,380,071       6,815,750  
Depreciation, depletion and amortization
    11,899,620       1,607,319       201,684  
Impairment of natural gas and oil properties
    642,374             707,523  
General and administrative expense
    16,928,760       6,841,721       4,760,662  
                         
Total expenses
    41,976,111       11,720,227       12,482,406  
                         
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE OTHER INCOME AND INCOME TAXES
    74,521,602       2,419,934       (11,706,075 )
OTHER INCOME (EXPENSE):
                       
Interest expense (net of interest capitalized)
    (3,933,309 )     (2,162,573 )     (54,488 )
Interest income
    1,969,145       886,420       826,399  
Gain (loss) on sale of assets and other
    62,314,188       (2,684,062 )     249,611  
                         
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    134,871,626       (1,540,281 )     (10,684,553 )
Benefit (provision) from income taxes
    (51,650,422 )     462,569       3,797,038  
                         
INCOME (LOSS) FROM CONTINUING OPERATIONS
    83,221,204       (1,077,712 )     (6,887,515 )
                         
DISCONTINUED OPERATIONS (Note 5)
                       
Discontinued operations, net of income taxes
    173,685,065       (1,616,839 )     6,680,552  
                         
NET INCOME (LOSS)
    256,906,269       (2,694,551 )     (206,963 )
Preferred stock dividends
    1,547,777       539,722       601,000  
                         
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
  $ 255,358,492     $ (3,234,273 )   $ (807,963 )
                         
NET INCOME (LOSS) PER SHARE:
                       
Basic
                       
Continuing operations
  $ 5.05     $ (0.11 )   $ (0.50 )
Discontinued operations
    10.73       (0.10 )     0.45  
                         
Total
  $ 15.78     $ (0.21 )   $ (0.05 )
                         
Diluted
                       
Continuing operations
  $ 4.82     $ (0.11 )   $ (0.50 )
Discontinued operations
    10.06       (0.10 )     0.45  
                         
Total
  $ 14.88     $ (0.21 )   $ (0.05 )
                         
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
                       
Basic
    16,184,517       15,430,146       14,760,268  
                         
Diluted
    17,262,715       15,430,146       14,760,268  
                         
 
The accompanying notes are an integral part of these consolidated financial statements.


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Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended June 30,  
    2008     2007     2006  
 
CASH FLOWS FROM OPERATING ACTIVITIES:
                       
Income (loss) from continuing operations
  $ 83,221,204     $ (1,077,712 )   $ (6,887,515 )
Income (loss) from discontinued operations, net of income taxes
    173,685,065       (1,616,839 )     6,680,552  
                         
Net income (loss)
    256,906,269       (2,694,551 )     (206,963 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                       
Depreciation, depletion and amortization
    15,173,285       3,267,252       1,199,436  
Impairment of natural gas and oil properties
    1,234,111       192,109       707,523  
Exploration expenditures
    4,747,798       5,473,218       8,221,045  
Deferred income taxes
    115,952,055       692,818       7,139  
Loss (gain) on sale of assets
    (326,337,749 )     2,313,334       (7,232,351 )
Stock-based compensation
    1,476,988       1,492,765       856,412  
Tax benefit from exercise of stock options
    (1,080,562 )     (188,897 )     (359,772 )
Changes in operating assets and liabilities:
                       
Decrease (increase) in accounts receivable and other
    (67,279,024 )     (7,599,816 )     947,586  
Increase in notes receivable
    (250,000 )     (1,005,000 )      
Increase in prepaid insurance
    (447,202 )     (205,904 )     (20,640 )
Increase in inventory
          (139,972 )     (194,825 )
Increase in accounts payable and advances from joint owners
    26,152,482       4,570,213       6,219,698  
Increase (decrease) in other accrued liabilities
    75,997,351       (87,286 )     792,025  
Increase (decrease) in income taxes payable
    7,210,622       (2,377,988 )     (1,398,776 )
Other
    3,286,631       370,723       (64,921 )
                         
Net cash provided by operating activities
    112,743,055       4,073,018       9,472,616  
                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
Natural gas and oil exploration and development expenditures
    (119,928,546 )     (77,688,085 )     (33,804,518 )
Investment in Freeport LNG Project
                (236,834 )
Sale of short-term investments, net
    2,200,576       16,271,751       7,027,542  
Additions to furniture and equipment
    (43,225 )     (26,659 )     (20,425 )
Decrease in advances to operators
                1,137,056  
Investment in Contango Venture Capital Corporation
    (1,166,624 )     (681,244 )     (2,156,447 )
Acquisition of overriding royalty interests
                (1,000,000 )
Acquisition of Republic Exploration LLC and Contango Offshore Exploration LLC interests
                (7,500,000 )
Acquisition of natural gas and oil producing properties
    (309,000,000 )            
Sale/Acquisition costs
    (7,847,613 )           (7,170 )
Proceeds from the sale of assets
    396,925,821       7,000,000       12,892,916  
                         
Net cash used in investing activities
    (38,859,611 )     (55,124,237 )     (23,667,880 )
                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
Borrowings under credit facility
    35,000,000       25,000,000       10,000,000  
Repayments under credit facility
    (40,000,000 )     (15,000,000 )      
Borrowings (repayments) by affiliates
    (8,540,091 )     8,540,091        
Proceeds from preferred equity issuances, net of issuance costs
          28,783,936       9,616,438  
Preferred stock dividends
    (1,547,777 )     (539,722 )     (601,000 )
Repurchase/cancellation of stock options
    (5,922,532 )     (202,521 )      
Purchase of shares
    (663,900 )            
Proceeds from exercise of options and warrants
    580,760       519,715       1,535,880  
Tax benefit from exercise of stock options
    1,080,562       188,897       359,772  
Debt issue costs
    (163,510 )     (336,509 )     (426,651 )
                         
Net cash provided by (used in) financing activities
    (20,176,488 )     46,953,887       20,484,439  
                         
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    53,706,956       (4,097,332 )     6,289,175  
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
    6,177,618       10,274,950       3,985,775  
                         
CASH AND CASH EQUIVALENTS, END OF PERIOD
  $ 59,884,574     $ 6,177,618     $ 10,274,950  
                         
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
                       
Cash paid for taxes, net of cash received
  $ 21,974,825     $ 451,993     $ 1,045,816  
                         
Cash paid for interest
  $ 4,305,336     $ 2,702,672     $ 125,582  
                         
 
The accompanying notes are an integral part of these consolidated financial statements.


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Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
 
                                                                                 
                                  Accumulated
                         
                                  Other
                Total
       
    Preferred Stock     Common Stock     Paid-in
    Comprehensive
    Treasury
    Retained
    Shareholders’
    Comprehensive
 
    Shares     Amount     Shares     Amount     Capital     Income     Stock     Earnings     Equity     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          
                                                                                 
                                                                                 
Exercise of stock options
                71,000       2,840       577,920                         580,760          
                                                                                 
Tax benefit from exercise of stock options
                            611,726                         611,726          
                                                                                 
Cancellation of stock options, net of tax benefit of $468,836
                            (5,453,696 )                       (5,453,696 )        
                                                                                 
Treasury shares at cost
                (10,000 )                       (663,900 )           (663,900 )        
                                                                                 
Amortization of restricted stock
                4,471       179       252,257                         252,436          
                                                                                 
Conversion of Series E preferred stock to common stock
    (6,000 )     (240 )     789,468       31,579       (31,339 )                                
                                                                                 
Expense of stock options
                            1,224,552                         1,224,552          
                                                                                 
Net income
                                              256,906,269       256,906,269       256,906,269  
                                                                                 
Preferred stock dividends
                                              (1,547,777 )     (1,547,777 )        
                                                                                 
Unrealized gain on available for sale securities, net of tax
                                  (715,659 )                 (715,659 )     (715,659 )
                                                                                 
                                                                                 
Comprehensive income
                                                        $ 254,211,718  
                                                                                 
                                                                                 
Balance at June 30, 2008
        $       16,819,746     $ 776,189     $ 73,030,926     $     $ (6,843,900 )   $ 275,035,266     $ 341,998,481          
                                                                                 
 
The accompanying notes are an integral part of these consolidated financial statements.


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Table of Contents

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 business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico.
 
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, 2008 and 2007, 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, 2008, the Company had $59.9 million in cash and cash equivalents, of which $25.1 million was invested in highly liquid AAA-rated money market funds.
 
Short Term Investments.  As of June 30, 2007, the Company had $2,200,576 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. The Company had no funds invested in PAR securities as of June 30, 2008.
 
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. A portion 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.
 
Accounts receivable allowance for bad debt was $0 at June 30, 2008 and 2007. At June 30, 2008 and 2007, 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


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Table of Contents

 
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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. In accordance with FASB Interpretation No. 48, “Accounting for uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”, the Company reviews its tax position for tax uncertainties.
 
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.
 
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.


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Table of Contents

 
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 the following asset sales as discontinued operations: its $128.0 million Western core Arkansas Fayetteville Shale sale effective October 1, 2007, its $199.2 million Eastern core Arkansas Fayetteville Shale sale effective December 1, 2007, its $1.1 million Alta-Ellis #1 and Temple Inland sale effective February 1, 2008, its $11.6 million property sale effective April 1, 2006 and its $2.0 million property sale effective February 1, 2006. 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 wholly and partially-owned subsidiaries, after elimination of all intercompany balances and transactions. Wholly-owned subsidiaries are fully consolidated. Exploration and development subsidiaries not wholly owned, such as 32.3% owned Republic Exploration LLC (“REX”) and 65.6% owned Contango Offshore Exploration LLC (“COE”), each as of June 30, 2008, are not controlled by the Company and are proportionately consolidated.
 
Upon the formation of REX, 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, REX completed exploration activities to fully expend the Company’s initial cash contribution, thereby enabling each owner to share in the net assets of REX based on their stated ownership percentages. Commencing with the quarter ended December 31, 2002, the Company began consolidating 33.3% of the net assets and results of operations of REX. The reduction of our ownership in the net assets of REX 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 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 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.
 
Effective April 1, 2008, the Company sold a portion of its ownership interest in REX and COE to an existing owner for approximately $0.8 million and $0.9 million, respectively. As a result of the sale, the Company’s equity ownership interest in REX and COE has decreased to 32.3% and 65.6%, respectively.
 
Contango’s 19.5% ownership of Moblize Inc. (“Moblize”) 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.


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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Recent Accounting Pronouncements.  FASB Staff Position No. EITF 03-6-1 (EITF 03-6-1). EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the two-class method described in SFAS No. 128, Earnings per Share. The provisions of EITF 03-6-1 are effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period EPS data presented shall be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data) to conform with the provisions of EITF 03-6-1. Early application is not permitted. We do not expect EITF 03-6-1 to have a material effect on our consolidated financial statements.
 
In May 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 162 (“SFAS 162”), “The Hierarchy of Generally Accepted Accounting Principles”. SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP (the GAAP hierarchy). SFAS 162 is effective 60 days following the Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendments to AU section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” We are currently evaluating the provisions of SFAS 162 and assessing the impact, if any, it may have on our financial position and results of operations.
 
Effective July 1, 2009, the FASB issued SFAS No. 157-2 (“SFAS 157-2”), “Effective Date of FASB Statement No. 157”. This pronouncement defers the effective date of SFAS No. 157 (“SFAS 157”), “Fair Value Measurements” to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years, for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). An entity that has issued interim or annual financial statements reflecting the application of the measurement and disclosure provisions of SFAS 157 prior to February 12, 2008, must continue to apply all provisions of SFAS 157. We are currently evaluating the impact of our adoption of SFAS 157-2 on our consolidated financial statements.
 
In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141(R) (“SFAS 141(R)”), “Business Combinations” and SFAS No. 160 (“SFAS 160”), “Noncontrolling Interests in Consolidated Financial Statements”. These statements require most identifiable assets, liabilities and noncontrolling interests to be recorded at full fair value and require noncontrolling interests to be reported as a component of equity. Both statements are effective for periods beginning on or after December 15, 2008, and earlier adoption is prohibited. SFAS 141(R) will be applied to business combinations occurring after the effective date and SFAS 160 will be applied prospectively to all noncontrolling interests, including any that arose before the effective date. We are currently evaluating the provisions of SFAS 141(R) and SFAS 160 and assessing the impact, if any, they may have on our financial position and results of operations.
 
In February 2007, the 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 and cash flows.
 
In September 2006, the FASB issued SFAS 157. 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


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Table of Contents

 
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We are currently evaluating the impact that SFAS 157 may have on our financial position, results of operations and cash flows.
 
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. No options were granted for the fiscal year ended June 30, 2008. For the fiscal years ended June 30, 2007 and 2006, the following weighted-average assumptions were used: (i) risk-free interest rate of 5.0 percent and 5.1 percent, respectively; (ii) expected lives of five years; (iii) expected volatility of 56 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, 2008, the Company granted 4,140 shares of restricted stock to its board of directors. 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 Chief Executive Officer at a fair value of $11.25 per option, to be expensed over the vesting period. During the years ended June 30, 2008, 2007 and 2006, the Company recorded a charge of $1.2 million, $1.3 million and $0.9 million 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, 2008, 2007 or 2006, nor did we have any open commodity derivative contracts at June 30, 2008.
 
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


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Table of Contents

 
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
the Company’s focus on offshore properties during the past few years, the ARO has increased since June 30, 2005. Activities related to the Company’s ARO during the year ended June 30, 2008 and 2007 are as follows:
 
                 
    Year Ended June 30,  
    2008     2007  
 
Initial ARO as of July 1
  $ 862,344     $ 665,458  
Liabilities incurred during period
    1,222,402       460,886  
Liabilities settled during period
          (264,000 )
Accretion expense
    (134,865 )      
                 
Balance of ARO as of June 30
  $ 1,949,881     $ 862,344  
                 
 
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.   Customer Concentration Credit Risk
 
The customer base for the Company is primarily concentrated in the natural gas and oil exploration industry. The majority of the Company’s revenues for the fiscal year ended June 30, 2008, approximately 59%, resulted from oil and gas sales to a single customer, Cokinos Energy Corporation. The receivables associated with the revenues from Cokinos Energy Corporation 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.
 
Other major purchasers of our natural gas and oil for the fiscal year ended June 30, 2008 include ConocoPhillips Company (24%) and Shell Trading US Company (8%).
 
5.   Sale of Properties — Discontinued Operations
 
On December 21, 2007, the Company sold its Western core Arkansas Fayetteville Shale properties to Petrohawk Energy Corporation for $199.2 million. The sale was effective October 1, 2007. The Company sold approximately 14,200 acres with 6.4 million cubic feet per day (“Mmcfd”) of production, net to Contango. The Company recognized a gain of approximately $155.9 million for the fiscal year ended June 30, 2008 as a result of this sale. The Company’s proved and unproved properties as of June 30, 2007 were reduced by approximately $43.3 million as a result of classifying this sale as discontinued operations.
 
On January 30, 2008, the Company sold its Eastern core Arkansas Fayetteville Shale properties to XTO Energy, Inc. for approximately $128.0 million. The sale was effective December 1, 2007. The Eastern core consisted of approximately 11,200 acres with 3.0 Mmcfd of production, net to Contango. The Company recognized a gain of approximately


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Table of Contents

 
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
$106.4 million for the fiscal year ended June 30, 2008 as a result of this sale. The Company’s proved and unproved properties as of June 30, 2007 were reduced by approximately $21.6 million as a result of classifying this sale as discontinued operations.
 
Effective February 1, 2008, the Company sold its interest in two on-shore wells to Alta Resources LLC. The Alta-Ellis #1 in Texas and the Temple-Inland in Louisiana were sold for approximately $1.1 million.
 
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 accordance with SFAS 144, we classified our property sales as discontinued operations in our financial statements for all periods presented.
 
The summarized financial results for discontinued operations for the periods ended June 30, 2008, 2007 and 2006 are as follows:
 
                         
    June 30,  
    2008     2007     2006  
 
Operating Results:
                       
Revenues
  $ 9,679,330     $ 4,547,661     $ 5,018,064  
Operating (expenses) credits*
    (1,144,786 )     (780,709 )     1,503,706  
Depletion expenses
    (3,273,655 )     (1,659,933 )     (997,752 )
Exploration expenses
    (359,888 )     (4,402,354 )     (2,479,376 )
Impairment
    (591,737 )     (192,109 )      
Gain on sale of discontinued operations
    262,898,530             7,233,130  
                         
Gain before income taxes
  $ 267,207,794     $ (2,487,444 )   $ 10,277,772  
(Provision) benefit for income taxes
    (93,522,729 )     870,605       (3,597,220 )
                         
Gain from discontinued operations, net of income taxes
  $ 173,685,065     $ (1,616,839 )   $ 6,680,552  
                         
 
 
* Credits due to severance tax refunds
 
For the year ended June 30, 2006, operating expenses from discontinued operations resulted in a net credit of $1.5 million. 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.


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Table of Contents

 
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
6.   Sale of Properties — Other
 
Freeport LNG Development, L.P.
 
On February 5, 2008, the Company sold its ten percent (10%) limited partnership interest in Freeport LNG Development L.P. (“Freeport LNG”) to Turbo LNG LLC, an affiliate of Osaka Gas Co., Ltd., for $68.0 million, and recognized a pre-tax gain of approximately $63.4 million on the sale. Freeport LNG is a limited partnership formed to develop, construct and operate a 1.75 billion cubic feet per day (“Bcfd”) liquefied natural gas (“LNG”) receiving and gasification terminal on Quintana Island, near Freeport, Texas. The Company used $20.3 million of the proceeds from the sale to pay off its debt with The Royal Bank of Scotland plc, including principal, interest and fees. Another $20.0 million was used to pay off its debt with a private investment firm. The remaining $27.7 million was used for working capital purposes.
 
Contango Venture Capital Corporation
 
In March 2008, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, sold its direct and indirect investments in Gridpoint, Inc., Trulite, Inc., Protonex Technology Corporation, Jadoo Power Systems, Contango Capital Partners