Form 10-K
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-K

 


 

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

SECURITIES EXCHANGE ACT OF 1934

 

For the Fiscal Year Ended June 30, 2005

 

Commission file number 000-24971

 


 

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

(Issuer’s telephone number)

 


 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

 

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

 

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

 

The aggregate market value of the voting common equity held by non-affiliates computed by reference to the average bid and asked price of such common equity at the close of business on September 7, 2005, was $137,420,706. As of September 7, 2005, there were 14,714,471 shares of the issuer’s common stock outstanding.

 

Documents Incorporated by Reference

 

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

 



Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K FOR THE FISCAL ENDED JUNE 30, 2005

 

TABLE OF CONTENTS

 

         Page

PART I     

Item 1.

  Business     
             Overview    1
             Our Strategy    1
             Exploration Alliances with JEX, Alta, Ameritex and Coastline    2
             Onshore Exploration and Properties    3
             Offshore Gulf of Mexico Exploration Joint Ventures    5
             Contango Operators, Inc.    7
             Offshore Properties    8
             Freeport LNG Development, L.P.    11
             Contango Venture Capital Corporation    12
             Marketing and Pricing    13
             Competition    13
             Governmental Regulations    13
             Employees    17
             Directors and Executive Officers    17
             Corporate Offices    19
             Code of Ethics    19
             Risk Factors    19
             Available Information    27

Item 2.

  Description of Properties     
             Production, Prices and Operating Expenses    27
             Development, Exploration and Acquisition Capital Expenditures    27
             Drilling Activity    28
             Exploration and Development Acreage    28
             Productive Wells    29
             Natural Gas and Oil Reserves    29

Item 3.

  Legal Proceedings    30

Item 4.

  Submission of Matters to a Vote of Security Holders    30
PART II     

Item 5.

  Market for Registrant’s Common Equity and Related Stockholder Matters    30

Item 6.

  Selected Financial Data    32

Item 7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations     
             Overview    34
             Results of Operations    35
             Capital Resources and Liquidity    38
             Contractual Obligations    40
             Credit Facility    40
             Critical Accounting Policies    40

Item 7A.

  Quantitative and Qualitative Disclosure about Market Risk    45

Item 8.

  Financial Statements and Supplementary Data    45

Item 9.

  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    45

Item 9A.

  Controls and Procedures    45

Item 9B.

  Other Information    46
PART III     

Item 10.

  Directors and Executive Officers of the Registrant    46

Item 11.

  Executive Compensation    46

Item 12.

  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    46

 

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Item 13.

  Certain Relationships and Related Transactions    46

Item 14.

  Principal Accountant Fees and Services    46
PART IV     

Item 15.

  Exhibits and Financial Statement Schedules    46

 

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 and budgets

 

    Anticipated capital expenditures

 

    Drilling of wells

 

    Natural gas and oil reserves

 

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

 

    Operating costs and other expenses

 

    Cash flow and anticipated liquidity

 

    Prospect development

 

    Property acquisitions and sales

 

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

 

    Investment in alternative energy

 

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

 

    Low and/or declining prices for natural gas and oil

 

    Natural gas and oil price volatility

 

    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

 

    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

 

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

 

    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 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

 

    Ability to find and retain skilled personnel

 

    Strength and financial resources of competitors

 

    Federal and state regulatory developments and approvals

 

    Environmental risks

 

    Worldwide economic conditions

 

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

 

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

 

    Successful commercialization of alternative energy technologies

 

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 19 of this report for some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in forward-looking statements.

 

 

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

 

PART I

 

Item 1. Business

 

Overview

 

Contango is a Houston-based, independent natural gas and oil company. The Company’s core business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico and onshore along the Gulf Coast. As a recent addition to our business, we will begin acting as an operator on certain offshore prospects through our wholly-owned subsidiary, Contango Operators, Inc. (“COI”). The Company also owns a 10% interest in a limited partnership formed to develop an LNG receiving terminal in Freeport, Texas, and holds investments in the alternative energy venture capital market with a focus on environmentally preferred energy technologies.

 

Our Strategy

 

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

 

Funding exploration prospects generated by our alliance partners. We depend on alliance partners for prospect generation expertise. Our four alliance partners, Juneau Exploration, L.P. (“JEX”), Alta Resources, LLC (“Alta”), Ameritex Minerals and Exploration, Ltd. (“Ameritex”) and Coastline Exploration, Inc. (“Coastline”) perform all of our prospect generation and evaluation functions.

 

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

 

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

 

Negotiated acquisitions of proved properties. We continue to seek negotiated acquisitions of producing properties based on our view of the pricing cycles of natural gas and oil and available reserve exploitation opportunities. Since January 1, 2002, we have acquired approximately 14 billion cubic feet equivalent (“Bcfe”) of proved developed producing reserves of natural gas and oil for approximately $26 million.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Exploration Alliances with JEX, Alta, Ameritex and Coastline

 

Alliance with JEX. JEX is a private company formed for the purpose of assembling domestic natural gas and oil prospects. Under our agreement with JEX, JEX generates natural gas and oil prospects and evaluates exploration prospects generated by others. JEX focuses exclusively on the Gulf of Mexico, and generates offshore exploration prospects via our affiliated companies, REX and Contango Offshore Exploration, LLC (“COE”) (see “Offshore Gulf of Mexico Exploration Joint Ventures” below).

 

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

 

Alliance with Ameritex. In February 2004, we entered into an exploration agreement with Ameritex, a privately held San Antonio based prospect generation and exploration company. Our participation percentage, which is exercisable at our option, is typically a 33.3% working interest, with Ameritex receiving a carried working interest to casing point. Our annual geological and geophysical cost for this prospect generation effort is approximately $80,000.

 

Alliance with Coastline. Coastline is a private company engaged in domestic, onshore natural gas and oil exploration and production. Our arrangement with Coastline generally provides for us to pay all leasehold costs, with Coastline generally receiving a negotiated overriding royalty interest and a carried working interest to casing point.

 

Onshore Exploration and Properties

 

JEX Activities

 

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

 

Alta Activities

 

In October 2003, Contango and Alta completed a 3-D seismic shoot covering approximately 40 square miles in southern Duval County, Texas. Using this data, Contango and Alta successfully drilled two Queen City prospects that commenced production in September 2004. In October 2004, we participated with Alta in drilling a third exploratory Queen City well in Jim Hogg County, Texas. The well was determined to be a dry hole and has since been plugged and abandoned. Our 45% share of the dry hole cost was approximately $0.4 million.

 

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

 

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

 

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

 

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

 

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

 

In June 2005, we participated with Alta in drilling an unsuccessful exploratory well in Bandera County, Texas. Our 50% share of the dry hole cost was approximately $0.6 million.

 

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

 

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

 

Ameritex Activities

 

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

 

In March 2005, we participated with Ameritex in drilling an exploratory well, the Garza #1, located in Zapata County, Texas. The well was determined to be a dry hole and has been plugged and abandoned. Our 19% share of dry hole and leasehold costs was approximately $1.2 million. We also drilled two exploratory wells, the Hargis #1 located in Live Oak County, Texas and the Thompson #1 located in Zavala County, Texas. Both wells were determined to be dry holes and have since been plugged and abandoned. Our 29.5% share of the dry hole and leasehold costs for both wells was approximately $0.8 million.

 

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

 

In June 2005, we successfully drilled the Gonzalez Benavides Trust #1, an exploratory well located in Zapata County, Texas. Our 33% share of the drilling costs is estimated at $0.7 million and our net revenue interest is approximately 18.8%. The well has been completed and is currently awaiting a pipeline connection. Production is expected to begin in October 2005.

 

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

 

Coastline Activities

 

In October 2004, Coastline purchased 3-D seismic data on an approximate 22 square mile area along with a lease option for an initial 180 day period, providing Coastline the right to purchase leases on 15,060 acres in Jim Hogg County, Texas. The lease option was renewed for an additional 90 days and expired. We agreed to pay 100% of the prospect leasehold costs and carry Coastline on a portion of the drilling costs on the first three wells located within the designated prospect area. In addition, Coastline would receive a 3% overriding royalty interest.

 

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

 

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

 

Sale of South Texas Properties

 

In December 2004, the Company completed the sale of the majority of its south Texas natural gas and oil interests to Edge Petroleum Corporation for $50 million. The sale was approved by a majority of the Company’s stockholders at a Special Meeting of Stockholders on December 29, 2004. Approximately 16 Bcfe of proven reserves were sold having a pre-tax net present value using a 10% discount rate as of June 30, 2004 of $54.3 million. Pre-tax proceeds after netting adjustments were $40.1 million. Adjustments were made for net revenues that Contango received for production occurring after July 1, 2004, the effective date of sale, up to the post-closing date of March 29, 2005. The Company recognized a gain on sale of approximately $16.3 million for the year ended June 30, 2005.

 

Offshore Gulf of Mexico Exploration Joint Ventures

 

Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. As of June 30, 2005, Contango and its affiliates had interests in 50 offshore leases. As of September 7, 2005, Contango and its affiliates have interests in 52 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.

 

As of June 30, 2005 Contango owned a 33.3% equity interest in REX, a 66.7% equity interest in COE, and a 50.0% equity interest in Magnolia Offshore Exploration LLC (“MOE”), all of which were formed for the purpose of generating exploration opportunities in the Gulf of Mexico. These companies have collectively licensed approximately 3,800 blocks of 3-D seismic data and have focused on identifying prospects, acquiring leases at federal and state lease sales and then selling the prospects to third parties, including Contango, subject to timed drilling obligations plus retained reversionary interests in favor of REX and COE.

 

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Republic Exploration LLC. As of June 30, 2005, Contango had approximately $5.7 million invested in REX for a 33.3% ownership interest. The other members of REX are JEX, its managing member, and a privately held seismic company. Both have comprehensive offshore experience. REX holds a non-exclusive license to approximately 2,030 blocks of 3-D seismic data in the shallow waters of the Gulf of Mexico. This data is used to identify, acquire and exploit natural gas and oil prospects. All leases owned by REX are subject to a 3.3% overriding royalty interest in favor of the JEX prospect generation team. See “Offshore Properties” below for more information on REX’s offshore properties. In addition, please see “Subsequent Events” on page F-25 for a discussion of our recent purchase of additional interests in REX.

 

Contango Offshore Exploration LLC. As of June 30, 2005, Contango had approximately $13.7 million invested in COE for a 66.7% ownership interest. JEX is the only other member and acts as the managing member. COE had invested approximately $13.7 million to acquire and reprocess 1,775 blocks of 3-D seismic data and to acquire leases in the Gulf of Mexico. All leases are subject to a 3.3% overriding royalty interest in favor of the JEX prospect generation team. See “Offshore Properties” below for additional information on COE’s offshore properties. In addition, please see “Subsequent Events” on page F-25 for a discussion of our recent purchase of additional interests in COE.

 

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

 

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

 

In March 2005, REX and COE were high bidders on three lease blocks that were offered at the Central Gulf of Mexico Lease Sale #194. REX acquired the West Cameron 107 offshore Gulf of Mexico lease block for approximately $0.3 million and COE acquired the Viosca Knoll 475 offshore Gulf of Mexico lease block for approximately $0.3 million and REX and COE each acquired a 50% working interest in the Eugene Island 168 lease block.

 

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

 

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

 

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REX and COE have farmed out the following five lease blocks: Main Pass 221, East Breaks 369/370, Vermillion 154, and the West Cameron 133. Main Pass 221 is expected to be drilled by the end of calendar year 2005, in which COE will receive a 5% overriding royalty interest before payout and a 7.2% overriding royalty interest after payout.

 

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

 

REX has recently entered into a letter of intent to farm out and drill an exploratory well on West Cameron 133, whereby REX will receive a 5% overriding royalty interest at first production with an option to escalate to either an 8.33% overriding royalty interest or receive a 25% working interest after payout. REX will be fully carried in the drilling costs and expects an exploratory well to be drilled in the spring of 2006. The Vermillion 154 prospect has been farmed out and REX expects the exploratory well to be drilled in July 2008.

 

Record title interest in the Vermilion 73 and South Marsh Island 247 leases has been assigned to a common third party. The South Marsh Island 247 prospect is in the process of being farmed out, and if successful, a timetable for drilling the prospect will then be established. REX reserves a 5% overriding royalty interest before payout in both prospects. In the Vermilion 73 prospect, REX also has the option after payout to maintain its 5% overriding royalty interest or acquire a 25% working interest in the prospect.

 

We recently drilled on our West Cameron 174 prospect. The well is in the process of being plugged and abandoned. Our 10% working interest share of the dry hole costs for the well is estimated at $0.8 million.

 

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

 

The Minerals Management Service (“MMS”) 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 well depths greater than 18,000 feet. This royalty relief is expected to have a positive impact on the economics of deep gas wells drilled on the shelf of the Gulf of Mexico.

 

Contango Operators, Inc.

 

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

 

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

 

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

 

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

 

Offshore Properties

 

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

 

Area/Block


   WI

    NRI

   

Status


Contango Operators, Inc:

                

Eugene Island 113B

   —       1.7 %   Producing

Republic Exploration LLC:

                

Eugene Island 113B

   —       3.3 %   Producing

Eugene Island 76

   (1 )   5.0 %   Production expected by fall 2005

Contango Offshore Exploration LLC:

                

Ship Shoal 358, A-3 well

   10.0 %   7.7 %   Producing

(1) REX has a 5% of 8/8 overriding royalty interest (“ORRI”) in the lease before payout. At payout, REX may elect to either (i) escalate its ORRI in the lease from 5% to 8-1/3% of 8/8 or (ii) convert the 5% ORRI to a 25% working interest (“WI”).

 

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

 

Area/Block


   WI

    NRI

   

Status


Republic Exploration LLC:

                

Vermilion 154

   (2 )   (2 )   Drilling expected by summer 2008

West Cameron 133

   (3 )   (3 )   Drilling expected by spring 2006

Contango Offshore Exploration LLC:

                

Vermilion 154

   (2 )   (2 )   Drilling expected by summer 2008

East Breaks 369

   (4 )   (4 )   Drilling expected by spring 2006

East Breaks 370

   (4 )   (4 )   Drilling expected by summer 2007

Main Pass 221

   (5 )   (5 )   Drilling expected by calendar year-end 2005

(2) REX and COE will split a 25% back-in WI after payout.
(3) REX has a 5% of 8/8 ORRI in the lease before first production. At first production, REX may elect to either (i) escalate its ORRI in the lease from 5% to 8-1/3% of 8/8 or (ii) convert the 5% ORRI to a 25% working interest (“WI”).
(4) COE has a 4.27% ORRI before payout and a 7.27% ORRI after payout.
(5) COE has a 5% of 8/8 ORRI before payout. Upon payout, COE’s ORRI will escalate to 7.2% of 8/8.

 

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

 

Area/Block


   WI

    Acquired

Contango Operators, Inc:

          

East Cameron 107

   33.8 %   May-01

Area/Block


   WI

    Acquired

Republic Exploration LLC:

          

East Cameron 107

   66.2 %   May-01

West Delta 36

   100.0 %   May-02

Vermilion 73

   (6 )   Jul-02

West Cameron 174

   100.0 %   Jun-03

High Island 113

   100.0 %   Sep-03

South Timbalier 191

   50.0 %   May-04

Vermilion 36

   100.0 %   May-04

Vermilion 109

   100.0 %   May-04

Vermilion 134

   100.0 %   May-04

West Cameron 179

   100.0 %   May-04

West Cameron 185

   100.0 %   May-04

West Cameron 200

   100.0 %   May-04

West Delta 18

   100.0 %   May-04

West Delta 33

   100.0 %   May-04

West Delta 34

   100.0 %   May-04

West Delta 43

   100.0 %   May-04

Ship Shoal 220

   50.0 %   May-04

South Timbalier 240

   50.0 %   May-04

South Marsh Island 247

   (7 )   Jul-04

Vermilion 130

   100.0 %   Jul-04

West Cameron 80

   100.0 %   Jul-04

West Cameron 167

   100.0 %   Jul-04

Eugene Island 168

   50.0 %   Mar-05

West Cameron 107

   100.0 %   Mar-05

S-L 18640 (LA)

   100.0 %   Aug-05

 

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Area/Block


   WI

    Acquired

Contango Offshore Exploration LLC:

          

Vermilion 231

   100.0 %   May-03

Viosca Knoll 167

   100.0 %   May-03

Eugene Island 209

   100.0 %   Jun-03

High Island A16

   100.0 %   Nov-03

East Breaks 283

   100.0 %   Nov-03

South Timbalier 191

   50.0 %   May-04

Grand Isle 63

   100.0 %   Jun-04

Grand Isle 72

   100.0 %   Jun-04

Grand Isle 73

   100.0 %   Jun-04

Ship Shoal 220

   50.0 %   May-04

South Timbalier 240

   50.0 %   May-04

Viosca Knoll 75

   33.3 %   May-02

Viosca Knoll 167

   100.0 %   May-03

Viosca Knoll 161

   33.3 %   Jun-03

Viosca Knoll 118

   33.3 %   May-04

Viosca Knoll 116

   33.3 %   May-05

Viosca Knoll 119

   33.3 %   May-05

Viosca Knoll 475

   100.0 %   Mar-05

Eugene Island 168

   50.0 %   Mar-05

Area/Block


   WI

    Acquired

Magnolia Offshore Exploration LLC:

          

Ship Shoal 155

   100.0 %   May-02

Viosca Knoll 75

   16.7 %   May-02

Viosca Knoll 161

   16.7 %   Jun-03

Viosca Knoll 118

   16.7 %   May-04

Viosca Knoll 211

   100.0 %   Jun-04

Viosca Knoll 116

   16.7 %   May-05

Viosca Knoll 119

   16.7 %   May-05

(6) Record title interest in lease has been assigned to a third party. REX has a 5% of 8/8 ORRI in the lease before payout. At payout, REX may elect to either (i) maintain its 5% ORRI in the lease or (ii) convert the 5% ORRI to a 25% WI.
(7) Record title interest in lease has been assigned to a third party. REX has reserved a 5% of 8/8 ORRI before payout.

 

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Freeport LNG Development, L.P.

 

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

 

In July 2004, Freeport LNG finalized its transaction with ConocoPhillips for the financing, construction and use of the LNG receiving terminal in Freeport, Texas. ConocoPhillips executed a terminal use agreement for 1 Bcf/d of regasification capacity, purchased a 50% interest in the general partner managing the Freeport LNG project and agreed to provide construction funding to the venture. This construction funding will be non-recourse to Contango. Dow Chemical has also executed a terminal use agreement for regasification capacity of 500 million cubic feet per day (“MMcf/d”) and, in an unrelated transaction with another limited partner, has purchased a 15% limited partnership interest in Freeport LNG. Freeport LNG is responsible for the commercial activities of the partnership, while ConocoPhillips, under a construction advisory and management agreement, is managing the construction of the facility.

 

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

 

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

 

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

 

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Contango Venture Capital Corporation

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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As of June 30, 2005, the Company recorded an approximate $0.75 million increase to our investment resulting primarily from unrealized gains of the Fund as a result of a mark-to-market adjustment that was made due to the increase in the value of our alternative energy investments, bringing our total investment to approximately $2.3 million.

 

Marketing and Pricing

 

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

 

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

 

    The domestic and foreign supply of natural gas and oil

 

    Overall economic conditions

 

    The level of consumer product demand

 

    Weather conditions

 

    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

 

Competition

 

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

 

Government Regulations

 

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

 

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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.

 

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

 

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

 

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

 

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

 

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

 

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

 

    Siting requirements

 

    Design standards

 

    Construction standards

 

    Equipment, operations and maintenance

 

    Personnel qualifications and training

 

    Fire protection

 

    Security

 

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

 

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

 

Other Federal Governmental Permits, Approvals and Consultations. In addition to the FERC authorization under Section 3 of the NGA, the construction and operation of LNG receiving terminals is also subject to additional federal and state permits, approvals and consultations including: Texas Commission on Environmental Quality, U.S. Coast Guard, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, U.S. Environmental Protection Agency (the “EPA”) and U.S. Department of Homeland Security and the Advisory Counsel on Historic Preservation.

 

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

 

CERCLA

 

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

 

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

 

Clean Air Act

 

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

 

Clean Water Act

 

LNG operations are also subject to the federal Clean Water Act (the “CWA”) and analogous state and local laws. Pursuant to certain requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit. In addition, our operations, including construction of LNG receiving terminals, in areas deemed to be wetlands, or which otherwise involve discharges of dredged or fill material into navigable waters of the United States, may be subject to Army Corps of Engineers permitting requirements.

 

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Hazardous Waste

 

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

 

Endangered Species

 

LNG operations may be restricted by requirements under the Endangered Species Act (the “ESA”) which seeks to ensure that human activities do not jeopardize endangered or threatened animal, fish and plant species nor destroy or modify their critical habitats.

 

Employees

 

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

 

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

   60      Chairman, President, Chief Executive Officer, Chief Financial Officer, Secretary and Director

Lesia Bautina

   34      Senior Vice President and Controller

Marc Duncan

   52      President & Chief Operating Officer, Contango Operators, Inc.

David Holcombe

   40      Assistant Treasurer

Jay D. Brehmer

   40      Director

Joseph S. Compofelice

   56      Director

Darrell W. Williams

   62      Director

 

Kenneth R. Peak. Mr. Peak has been Chairman and CEO of Contango since its formation in September 1999. Mr. Peak entered the energy industry in 1972 as a commercial banker and held a variety of financial and executive positions in the oil and gas industry prior to starting Contango in 1999. Mr. Peak served as an officer in the U.S. Navy from 1968 to 1971. Mr. Peak received a BS in physics from Ohio University and an MBA from Columbia University. He currently serves as a director of Patterson-UTI Energy, Inc., a provider of onshore contract drilling services to exploration and production companies in North America.

 

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

 

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

 

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

 

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

 

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

 

Darrell W. Williams. Mr. Williams has been a director of Contango since 1999. Mr. Williams is Managing Director of Catalina Capital Advisors LP, a boutique financial advisory, merger and acquisition investment bank. From 1993 until 2002, Mr. Williams was associated with the German firm of Deutag Drilling, GmbH in both marketing and operations positions. Prior to joining Deutag, Mr. Williams was in senior executive positions with Nabors Drilling (1988-1993), Pool Company (1985-1988), Baker Oil Tools (1980-1983), SEDCO (1970-1980), Tenneco (1966-1970), and Humble Oil (1964-1966). Mr. Williams graduated from West Virginia University with a degree in Petroleum Engineering in 1964. Mr. Williams is past Chairman of the Houston Chapter of International Association of Drilling Contractors, a life member of the Society of Petroleum Engineers and a registered professional engineer in Texas.

 

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

 

Corporate Offices

 

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

 

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.

 

Risk Factors

 

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

 

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

 

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

 

    The domestic and foreign supply of natural gas and oil.

 

    Overall economic conditions.

 

    The level of consumer product demand.

 

    Weather conditions.

 

    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.

 

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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 our alliance partners and could be seriously harmed if our alliance agreements were terminated.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

In December 2003, ConocoPhillips and Freeport LNG signed an agreement providing for ConocoPhillips’ participation in Freeport LNG’s project to build the receiving terminal. ConocoPhillips will acquire 1 Bcf/d of capacity in the terminal for its use. ConocoPhillips purchased a 50% interest in the general partner of Freeport LNG and, as noted above, has agreed to provide substantially all of the construction funding. Without such financing or upon any significant shortfall in project funding, we may not have the financial resources to fund our 10% ownership share of construction costs. If we are unable to fund our share of the project costs or if the project is unable to secure third-party project financing, we could lose our investment in the project.

 

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

 

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

 

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

 

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

 

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

 

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in this report. In addition, estimates of our proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control. Some of the producing wells included in our reserve report have produced for a relatively short period of time as of June 30, 2005. Because some of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a more lengthy production history.

 

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

 

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

 

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

 

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

 

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

 

    Unexpected drilling conditions.

 

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

 

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    Pressure or irregularities in formations.

 

    Equipment failures or accidents.

 

    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.

 

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.

 

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

 

    Injury or loss of life.

 

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

 

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

 

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

 

Not hedging our production may result in losses.

 

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

 

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

 

All of our natural gas and oil is transported through gathering systems and pipelines, which we do not own. Transportation capacity on gathering systems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to these facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation agreements. If the gathering systems or our transportation capacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition and results of operations.

 

We have no assurance of title to our leased interests.

 

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

 

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

 

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

 

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

 

    Timing and amount of capital expenditures.

 

    The operator’s expertise and financial resources.

 

    Approval of other participants in drilling wells.

 

    Selection of technology.

 

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

 

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

 

    Recoverable reserves.

 

    Exploration potential.

 

    Future natural gas and oil prices.

 

    Operating costs.

 

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    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.

 

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

 

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

 

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

 

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

 

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

 

    Limit the personal liability of directors.

 

    Limit the persons who may call special meetings of stockholders.

 

    Prohibit stockholder action by written consent.

 

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

 

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

 

    Impose restrictions on business combinations with some interested parties.

 

Our common stock is thinly traded.

 

Contango has approximately 14.7 million shares of common stock outstanding, held by approximately 115 holders of record. Approximately 2.6 million shares are owned by directors and officers. 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.

 

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Available Information

 

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

 

Item 2. Description of Properties

 

Production, Prices and Operating Expenses

 

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

 

     Year Ended June 30,

     2005

    2004

   2003

Production:

                     

Natural gas (thousand cubic feet)

     2,124,410       4,328,507      6,016,395

Oil and condensate (barrels)

     50,613       99,492      138,569

Total (thousand cubic feet equivalent)

     2,428,088       4,925,459      6,847,809

Natural gas (thousand cubic feet per day)

     5,820       11,827      16,483

Oil and condensate (barrels per day)

     139       272      380

Total (thousand cubic feet equivalent per day)

     6,654       13,459      18,763

Average sales price:

                     

Natural gas (per thousand cubic feet)

   $ 6.53     $ 5.65    $ 5.00

Oil and condensate (per barrel)

   $ 48.13     $ 31.99    $ 27.90

Total (per thousand cubic feet equivalent)

   $ 6.71     $ 5.61    $ 4.95

Selected data per Mcfe:

                     

Production and severance taxes

   $ (0.25 )   $ 0.16    $ 0.35

Lease operating expense

   $ 0.76     $ 0.63    $ 0.48

General and administrative expense

   $ 1.47     $ 0.55    $ 0.30

Depreciation, depletion and amortization of natural gas and oil properties

   $ 1.13     $ 1.39    $ 1.24

 

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,

     2005

   2004

   2003

Property Acquisition Costs:

                    

Unproved

   $ 248,634    $ 4,475,908    $ 972,658

Proved

     —        —        2,602,551

Exploration costs

     9,428,002      6,923,762      19,194,281

Developmental costs

     —        983,933      —  
    

  

  

Total costs

   $ 9,676,636    $ 12,383,603    $ 22,769,490
    

  

  

 

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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,

     2005

   2004

   2003

     Gross

   Net

   Gross

   Net

   Gross

   Net

Exploratory Wells:

                             

Productive

   4    1.4    8    3.9    11    5.2

Non-productive

   9    3.7    6    1.6    4    1.9
    
  
  
  
  
  

Total

   13    5.1    14    5.5    15    7.1
    
  
  
  
  
  

(1) The Company has not drilled any development wells since fiscal year 2004, when it drilled one gross development well (0.8 net developmental wells). The well was a productive well. No development wells were drilled in fiscal years 2003 and 2004.

 

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, 2005:

 

    

Developed

Acreage (1)(2)


  

Undeveloped

Acreage (1)(3)


     Gross (4)

   Net (5)

   Gross (4)

   Net (5)

Onshore Arkansas

   —      —      21,722    15,205

Onshore Alabama, Louisiana and Texas

   2,631    708    9,694    3,790

Offshore Gulf of Mexico, Texas and Louisiana

   5,000    333    178,796    81,392
    
  
  
  

Total

   7,631    1,041    210,212    100,387
    
  
  
  

(1) Excludes any interest in acreage in which we have no working interest before payout or before initial production.
(2) Developed acreage consists of acres spaced or assignable to productive wells.
(3) Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
(4) Gross acres refer to the number of acres in which we own a working interest.
(5) Net acres represent the number of acres attributable to an owner’s proportionate working interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is equivalent to 160 net acres).

 

Included in the 178,796 gross and 81,392 net 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 33.3% interest in Republic Exploration LLC’s 83,521 net undeveloped acres, (ii) our 66.7% interest in Contango Offshore Exploration LLC’s 333 net developed acres and in 66,128 net undeveloped acres, and (iii) our 50% interest in Magnolia Offshore Exploration LLC’s 15,560 net undeveloped acres. In addition, the Company holds royalty interests in approximately 63,363 gross undeveloped acres (3,118 net undeveloped acres) and 10,182 gross developed acres (224 net developed acres), both offshore in the Gulf of Mexico and onshore along the Gulf Coast.

 

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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, 2005:

 

     Total Productive
Wells (1)


     Gross (2)

   Net (3)

Natural gas

   6    1.4

Oil

   1    0.4
    
  

Total

   7    1.8
    
  

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

 

The pre-tax net present value of future cash flows attributable to our proved reserves prepared in accordance with SEC guidelines as of June 30, 2005 was based on $7.08 per million British thermal units (“MMbtu”) for natural gas at the Houston Ship Channel and $56.50 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, 2005

     Producing

   Non-Producing

   Behind Pipe

   Undeveloped

   Total

Natural gas (MMcf)

     783      38      90      —        911

Oil and condensate (MBbls)

     57      18      2      —        77

Total proved reserves (MMcfe)

     1,125      146      102      —        1,373

Pre-tax net present value ($000)

   $ 5,828    $ 1,014    $ 239    $ —      $ 7,081

 

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

 

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Table of Contents

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

 

Item 3. Legal Proceedings

 

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

 

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

 

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

 

PART II

 

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

 

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

 

     High

   Low

Fiscal Year 2004:

             

Quarter ended September 30, 2003

   $ 4.59    $ 3.88

Quarter ended December 31, 2003

   $ 7.03    $ 4.03

Quarter ended March 31, 2004

   $ 8.48    $ 6.42

Quarter ended June 30, 2004

   $ 7.82    $ 5.45

Fiscal Year 2005:

             

Quarter ended September 30, 2004

   $ 7.27    $ 6.05

Quarter ended December 31, 2004

   $ 8.22    $ 6.50

Quarter ended March 31, 2005

   $ 9.40    $ 6.75

Quarter ended June 30, 2005

   $ 9.34    $ 7.50

 

On September 7, 2005, the closing price of our common stock on the American Stock Exchange was $11.34 per share, and there were 14,714,471 shares of Contango common stock outstanding, held by approximately 115 holders of record.

 

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

 

On July 15, 2005, we sold $10.0 million of our Series D preferred stock to a group of private investors. The sale of the Series D 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 D preferred stock is perpetual and cumulative, is senior to our common stock and is convertible at any time into shares of our common stock at a price of $12.00 per share. The dividend on the Series D preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per annum. We intend to use the net proceeds to fund our Fayetteville Shale play, as well as our offshore Gulf of Mexico deep shelf exploration program, to fund any needed commitments to Freeport LNG

 

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Table of Contents

Development, LP (“Freeport LNG”) and the Contango Capital Partners Fund LP (the “Fund”), and for working capital and general corporate purposes. We have filed a registration statement with the Securities and Exchange Commission, covering the 833,330 shares of common stock issuable upon conversion of the Series D preferred stock.

 

On July 19, 2005, we exercised our mandatory conversion rights pursuant to the terms of our Series C preferred stock, and converted all of the 1,400 shares of our Series C preferred stock issued and outstanding at that time into 1,166,662 shares of common stock. The outstanding shares of the Series C preferred stock prior to their conversion, had a face value of $7 million, and paid a 6.0% per annum quarterly cash dividend. The shares of common stock issued upon conversion of the Series C preferred stock are registered with the Securities and Exchange Commission.

 

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Table of Contents

Item 6. Selected Financial Data

 

     Year Ended June 30,

 
     2005

    2004

    2003

    2002

   2001

 
     (Dollar amounts in 000s, except per share amounts)  

Financial Data:

        

Revenues:

                                       

Natural gas and oil sales

   $ 4,330     $ 195     $ 228     $ 292    $ 930  

Gain (loss) from hedging activities

     —         58       (5,709 )     5,016      (558 )
    


 


 


 

  


Total revenues

   $ 4,330     $ 253     $ (5,481 )   $ 5,308    $ 372  
    


 


 


 

  


Income (loss) from continuing operations

   $ (4,408 )   $ (3,154 )   $ (13,452 )   $ 764    $ (1,183 )

Discontinued operations, net of income taxes

     16,826       10,854       9,116       5,813      8,920  
    


 


 


 

  


Net income (loss)

   $ 12,418     $ 7,700     $ (4,336 )   $ 6,577    $ 7,737  

Preferred stock dividends

     420       620       600       600      475  
    


 


 


 

  


Net income (loss) attributable to common stock

   $ 11,998     $ 7,080     $ (4,936 )   $ 5,977    $ 7,262  
    


 


 


 

  


Net income (loss) per share:

                                       

Basic

                                       

Continuing operations

   $ (0.37 )   $ (0.36 )   $ (1.54 )   $ 0.01    $ (0.15 )

Discontinued operations

     1.29       1.04       1.00       0.54      0.79  
    


 


 


 

  


Total

   $ 0.92     $ 0.68     $ (0.54 )   $ 0.55    $ 0.64  
    


 


 


 

  


Diluted

                                       

Continuing operations

   $ (0.37 )   $ (0.36 )   $ (1.54 )   $ 0.01    $ (0.15 )

Discontinued operations

     1.29       1.04       1.00       0.50      0.79  
    


 


 


 

  


Total

   $ 0.92     $ 0.68     $ (0.54 )   $ 0.51    $ 0.64  
    


 


 


 

  


Weighted average shares outstanding:

                                       

Basic

     13,089       10,484       9,129       10,842      11,287  

Diluted

     13,089       10,484       9,129       11,575      11,287  

EBITDAX (1)

   $ 28,454     $ 28,986     $ 20,901     $ 22,486    $ 19,002  

Working capital (deficit)

   $ 28,839     $ 3,032     $ (1,676 )   $ 3,928    $ 4,782  

Capital expenditures

   $ 9,677     $ 12,384     $ 22,769     $ 31,651    $ 22,769  

Long term debt

   $ —       $ 7,089     $ 16,460     $ 17,620    $ —    

Shareholders’ equity

   $ 50,979     $ 36,117     $ 20,738     $ 25,098    $ 25,020  

Total assets

   $ 53,353     $ 45,511     $ 46,305     $ 51,840    $ 31,722  

 

 

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Table of Contents

Item 6. Selected Financial Data - continued

 

     Year Ended June 30,

     2005

    2004

   2003

   2002

   2001

Production Data:

                                   

Natural gas (million cubic feet)

     2,124       4,329      6,016      6,982      3,570

Oil and condensate (thousand barrels)

     51       99      139      186      122

Total (million cubic feet equivalent)

     2,430       4,923      6,850      8,098      4,302

Natural gas (thousand cubic feet per day)

     5,820       11,827      16,483      19,129      9,781

Oil and condensate (barrels per day)

     139       272      380      510      335

Total (thousand cubic feet equivalent per day)

     6,654       13,459      18,763      22,189      11,791

Average sales price:

                                   

Natural gas (per thousand cubic feet)

   $ 6.53     $ 5.65    $ 5.00    $ 2.94    $ 5.92

Oil and condensate (per barrel)

   $ 48.13     $ 31.99    $ 27.90    $ 21.44    $ 27.95

Selected data per Mcfe:

                                   

Production and severance taxes

   $ (0.25 )   $ 0.16    $ 0.35    $ 0.20    $ 0.39

Lease operating expenses

   $ 0.76     $ 0.63    $ 0.48    $ 0.28    $ 0.22

General and administrative expenses

   $ 1.47     $ 0.55    $ 0.30    $ 0.36    $ 0.55

Depreciation, depletion and amortization of natural gas and oil properties

   $ 1.13     $ 1.39    $ 1.24    $ 1.05    $ 0.92

Proved Reserve Data:

                                   

Total proved reserves (Mmcfe)

     1,373       17,422      23,592      27,939      18,144

Pre-tax net present value (SEC at 10%)

   $ 7,081     $ 59,767    $ 69,627    $ 53,349    $ 42,626

(1) EBITDAX represents earnings before interest, income taxes, depreciation, depletion and amortization, impairment expenses, exploration expenses, including gain (loss) from hedging activities, and sale of assets and other. We have reported EBITDAX because we believe EBITDAX is a measure commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. We believe EBITDAX assists investors in comparing a company’s performance on a consistent basis without regard to depreciation, depletion and amortization, impairment of natural gas and oil properties and exploration expenses, which can vary significantly depending upon accounting methods. EBITDAX is not a calculation based on U.S. generally accepted accounting principles and should not be considered an alternative to net income (loss) in measuring our performance or used as an exclusive measure of cash flow because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions and other sources and uses of cash, which are disclosed in our statements of cash flows. Investors should carefully consider the specific items included in our computation of EBITDAX. While we have disclosed our EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, investors should be cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service, preferred stock dividends and other commitments.

 

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Table of Contents

A reconciliation of EBITDAX to income (loss) from operations and operating results for discontinued operations for the periods indicated is presented below.

 

     Year ended June 30,

 
     2005

    2004

    2003

    2002

   2001

 
     ($000)  

Income (loss) from continuing operations

   $ (7,824 )   $ (11,517 )   $ (20,506 )   $ 1,353    $ (3,213 )

Exploration expenses

     6,607       8,847       12,641       477      389  

Depreciation, depletion and amortization

     1,233       41       27       217      298  

Impairment of natural gas and oil properties

     237       43       181       198      300  

Gain on sale of marketable securities

     —         710       452       —        —    

Gain on sale of assets and other

     705       6,188       39       374      —    
    


 


 


 

  


EBITDAX from continuing operations

     958       4,312       (7,166 )     2,619      (2,226 )

Income from discontinued operations before taxes

     25,886       16,699       14,025       8,944      13,724  

Exploration expenses

     27       1,026       5,281       2,217      3,778  

Depreciation, depletion and amortization

     1,583       6,949       8,761       8,377      3,726  

Impairment of natural gas and oil properties

     —         —         —         329      —    
    


 


 


 

  


EBITDAX

   $ 28,454     $ 28,986     $ 20,901     $ 22,486    $ 19,002  
    


 


 


 

  


 

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

 

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

 

Overview

 

Contango is a Houston-based, independent natural gas and oil company. The Company’s core business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico and onshore along the Gulf Coast. As a recent addition to our business, we will begin acting as an operator on certain offshore prospects through our wholly-owned subsidiary, Contango Operators, Inc. (“COI”). The Company also owns a 10% interest in a limited partnership formed to develop an LNG receiving terminal in Freeport, Texas, and holds investments in the alternative energy venture capital market with a focus on environmentally preferred energy technologies.

 

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

 

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

 

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

 

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Table of Contents

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 19 for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations.

 

Results of Operations

 

The following is a discussion of the results of our operations for the fiscal year ended June 30, 2005, compared to the fiscal year ended June 30, 2004 and for the fiscal year ended June 30, 2004, compared to the fiscal year ended June 30, 2003.

 

Revenues. All of our revenues are from the sale of our natural gas and oil production and the settlement of hedging contracts associated with our natural gas and oil production. Our revenues may vary significantly from year to year depending on changes in commodity prices and production volumes.

 

The table below sets forth revenue and production data for both continuing and discontinued operations the fiscal years ended June 30, 2005, 2004 and 2003:

 

     Year ended June 30,

         Year ended June 30,

       
     2005

   2004

   %

    2004

   2003

    %

 
     ($000)          ($000)        

Revenues:

                           

Natural gas and oil sales

   $ 16,267    $ 27,630    -41 %   $ 27,630    $ 33,919     -19 %

Gain (loss) from hedging activities

     —        58    *       58      (5,709 )   *  
    

  

        

  


     

Total revenues

   $ 16,267    $ 27,688          $ 27,688    $ 28,210        

Production:

                                         

Natural gas (million cubic feet)

     2,124      4,329    -51 %     4,329      6,016     -28 %

Oil and condensate (thousand barrels)

     51      99    -48 %     99      139     -29 %

Total (million cubic feet equivalent)

     2,430      4,923    -51 %     4,923      6,850     -28 %

Natural gas (million cubic feet per day)

     5.8      11.8    -51 %     11.8      16.5     -28 %

Oil and condensate (thousand barrels per day)

     0.1      0.3    -48 %     0.3      0.4     -29 %

Total (million cubic feet per day equivalent)

     6.7      13.5    -51 %     13.5      18.8     -28 %

Average Sales Price:

                                         

Natural gas (per thousand cubic feet)

   $ 6.53    $ 5.65    16 %   $ 5.65    $ 5.00     13 %

Oil and condensate (per barrel)

   $ 48.13    $ 31.99    50 %   $ 31.99    $ 27.90     15 %

Operating expenses

   $ 1,235    $ 3,888    -68 %   $ 3,888    $ 5,736     -32 %

Exploration expenses

   $ 6,634    $ 9,873    -33 %   $ 9,873    $ 17,922     -45 %

Depreciation, depletion and amortization

   $ 2,816    $ 6,989    -60 %   $ 6,989    $ 8,788     -20 %

Impairment of natural gas and oil properties

   $ 237    $ 43    450 %   $ 43    $ 182     -76 %

General and administrative expenses

   $ 3,571    $ 2,696    32 %   $ 2,696    $ 2,064     31 %

Interest expense

   $ 71    $ 362    -80 %   $ 362    $ 711     -49 %

Interest income

   $ 432    $ 38    1031 %   $ 38    $ 30     26 %

Gain on sale of marketable securities

   $ —      $ 710    *     $ 710    $ 451     *  

Gain on sale of assets and other

   $ 16,993    $ 7,172    137 %   $ 7,172    $ 39     18181 %

* Not meaningful

 

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Natural Gas and Oil Sales. We reported natural gas and oil sales of approximately $16.3 million for the year ended June 30, 2005, down from approximately $27.6 million reported for the year ended June 30, 2004. The decrease in revenue was primarily the result of the sale of our south Texas natural gas and oil interests for $50 million, completed in December 2004. Of the $16.3 million of revenue reported for the year period ended June 30, 2005, $11.9 million was attributed to the sold properties. The remaining $4.4 million of revenue reflects mainly added production from newly added reserves and production from the south Texas properties that were not included in the sale. This compares to $0.2 million of revenue, excluding revenue from the sold properties, for the year period ended June 30, 2004.

 

We reported natural gas and oil sales of approximately $27.6 million for the year ended June 30, 2004, down from approximately $33.9 million reported for the year ended June 30, 2003. This decrease was principally attributable to normal production declines in our existing south Texas properties and the sale of non-core producing properties in Brooks County, Texas. These declines were partially offset by increases in average prices received for our natural gas and oil production.

 

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the year ended June 30, 2005 was approximately 5.8 MMcf/d, down from approximately 11.8 MMcf/d for the year ended June 30, 2004. Net oil production for the comparable periods decreased from 272 barrels of oil per day to 139 barrels of oil per day. The decrease in natural gas and oil production was primarily the result of the sale of our south Texas natural gas and oil interests, offset by increased production resulting from additional wells drilled after June 30, 2004. For the year ended June 30, 2005, prices for natural gas and oil were $6.53 per Mcf and $48.13 per barrel, compared to $5.65 per Mcf and $31.99 per barrel for the year ended June 30, 2004.

 

For the year ended June 30, 2004, our net natural gas production was approximately 11.8 MMcf/d, down from approximately 16.5 MMcf/d for the year ended June 30, 2003. Net oil production for the period was down from 380 barrels of oil per day to 272 barrels of oil per day. These decreases primarily were due to normal production declines in our existing south Texas properties and the sale of non-core producing properties in Brooks County, Texas. For the year ended June 30, 2004, prices for natural gas and oil were $5.65 per Mcf and $31.99 per barrel, up from $5.00 per Mcf and $27.90 per barrel for the year ended June 30, 2003.

 

Gain (loss) from Hedging Activities. The Company did not engage in any hedging activity for the year ended June 30, 2005.

 

We reported a gain from hedging activities for the year ended June 30, 2004 of approximately $58,200. For the year ended June 30, 2003, we reported a loss from hedging activities of approximately $5.7 million. This loss included an approximate $5.8 million realized loss on various swap, put and call agreements that was offset by an unrealized gain of about $67,000.

 

Operating Expenses. Operating expenses, including severance taxes, for the year ended June 30, 2005 were approximately $1.2 million. Included in this amount was approximately $1.5 million of lease operating expense, approximately $0.3 million for workover costs and a $0.6 million credit for production and severance taxes. The Railroad Commission of Texas has extended a natural gas incentive allowing for severance tax reduction on tight sand gas wells. As a result, some of our south Texas Queen City formation properties are eligible for severance tax reduction. Comparable low levels of severance taxes should not necessarily be expected in future reporting periods.

 

Operating expenses, including severance taxes, for the year ended June 30, 2004 were approximately $3.9 million, down from the $5.7 million reported for the year ended June 30, 2003. Of the $3.9 million reported for the year ended June 30, 2004, approximately $3.1 million was attributable to lease operating expense and approximately $0.8 million was attributable to production and severance taxes. The decrease in operating expenses for the year ended June 30, 2004 was attributable to lower production and the extension of a natural gas incentive by the Railroad Commission of Texas to allow for severance tax reduction on tight sand gas wells. As a result, some of our south Texas Queen City formation properties were eligible for severance tax reduction.

 

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Exploration Expense. We reported approximately $6.6 million of exploration expenses for the year ended June 30, 2005. Of this amount, approximately $4.6 million was related to unsuccessful wells drilled in south Texas ($3.8 million) and the Gulf of Mexico ($0.8 million) during the period, approximately $1.6 million was attributable to the cost to acquire and reprocess 3-D seismic data both onshore along the Gulf Coast and offshore in the Gulf of Mexico, and $0.4 million was attributable to the cost of delay rentals.

 

We reported approximately $9.9 million of exploration expenses for the year ended June 30, 2004. Of this amount, approximately $3.6 million was attributable to dry holes drilled in south Texas ($2.8 million) and to our unsuccessful well drilled in France ($0.8 million), approximately $2.7 million was attributable to seismic costs and delay rentals associated with activities onshore in south Texas and approximately $3.6 million was attributable to seismic costs and delay rentals associated with activities offshore in the Gulf of Mexico.

 

We reported approximately $17.9 million of exploration expenses for the year ended June 30, 2003. Of this amount, approximately $11.9 million was attributable to the cost to acquire and reprocess 3-D seismic data offshore in the Gulf of Mexico, approximately $4.7 million was the cost to shoot and to acquire 3-D seismic in south Texas and approximately $1.3 million was related to dry hole costs in south Texas.

 

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the year ended June 30, 2005 was approximately $2.8 million. For the year ended June 30, 2004, we recorded approximately $7.0 million of depreciation, depletion and amortization. The decrease in depreciation, depletion and amortization was primarily the result of the sale of our south Texas properties. There was no depreciation, depletion and amortization expense recorded in the second and third quarters of 2005 related to those properties since those properties were classified as held for sale as of October 2004.

 

Depreciation, depletion and amortization for the fiscal years ended June 30, 2004 and 2003 were approximately $7.0 million and $8.8 million, respectively. Depreciation, depletion and amortization for these periods was attributable primarily to depletion and amortization related to production onshore in south Texas. The decrease in 2004 was primarily due to lower levels of production and a lower unit depreciation, depletion and amortization rate.

 

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

 

Impairment expense for the year ended June 30, 2004 and 2003 was approximately $43,000 and $181,600, respectively. These related to impairment of properties held by REX and MOE.

 

General and Administrative Expenses. General and administrative expenses for the year ended June 30, 2005 were approximately $3.6 million, up from $2.7 million for the year ended June 30, 2004. Major components of general and administrative expenses for the year ended June 30, 2005 included approximately $0.7 million in salaries and benefits, $0.6 million in bonuses, $1.2 million in office administration and other expenses, $0.3 million in insurance costs, $0.4 million in legal and other professional fees and other administrative expenses, and $0.4 million related to the cost of expensing stock options.

 

General and administrative expenses for the year ended June 30, 2004 were approximately $2.7 million, up from $2.1 million for the year ended June 30, 2003. Major components of general and administrative expenses for the year ended June 30, 2004 included approximately $0.7 million in salaries and benefits, $0.5 million of legal, accounting, engineering and other professional fees, $0.4 million of office administration and $0.3 million of insurance costs. Also included in total general and administrative expenses for the year ended June 30, 2004 was approximately $0.3 million related to the cost of expensing stock options, $0.2 million related to our Gulf of Mexico exploration activities, $0.1 million for Board compensation expense and $0.2 million in other expenses.

 

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Interest Expense. Interest expense for the fiscal years ended June 30, 2005, 2004 and 2003 were approximately $0.1 million, $0.4 million, and $0.7 million, respectively. The higher levels of interest for the fiscal years 2003 and 2004 were attributable to higher levels of bank debt during such periods. The lower level of interest in fiscal year 2005 was attributable to the Company retiring all of its long term debt in the second quarter of fiscal year 2005.

 

Gain on Sale of Assets and Other. We reported other income of approximately $17 million for the year ended June 30, 2005, which represented a $16.3 million gain on the sale of our south Texas natural gas and oil interests, a $0.75 million unrealized gain recorded as a result of a mark-to-market increase in the value of our alternative energy investments, offset by approximately $0.1 million in operating losses related to our alternative energy investments.

 

For the year ended June 30, 2004, we reported an approximate $7.2 million gain on the sale of assets. In September 2003, we sold properties within our south Texas exploration program consisting of 10 wells in Brooks County, Texas for $5.0 million, reporting a gain of approximately $1.0 million attributable to this producing property sale. In December 2003, Contango and its 33.3%-owned subsidiary, Republic Exploration LLC, sold their producing Gulf of Mexico leases for approximately $12.0 million. As a result of this sale, Contango recorded a gain of approximately $6.2 million as of June 30, 2004. Properties included in the sale were Eugene Island 110, Grand Isle 28 and High Island 25-L. Because the interests sold were unearned back-in working interests, Contango had no proved reserves attributable to the properties sold.

 

Capital Resources and Liquidity

 

Cash Inflow. During the year ended June 30, 2005, we funded our investing and financing activities with internally generated cash flow from operations of $4.9 million, net of income taxes. During the year we drilled a total of 13 wells, four of which were successful and nine of which were dry holes.

 

In December 2004, we completed the sale of the majority of our south Texas natural gas and oil interests to Edge Petroleum Corporation. Proceeds from the asset sale after netting adjustments were $40.1 million.

 

Cash Outflow. During the year ended June 30, 2005, we invested $7.6 million in exploration and development activities (net of reimbursements and advances), $0.9 million in our prospect generation and exploration subsidiaries, $0.7 million in our 10% owned Freeport LNG project, and $1.0 million in alternative energy companies vis-à-vis our investment in the Contango Capital Partners Fund, L.P. (the “Fund”).

 

During the year ended June 30, 2005, we paid a net of $5.0 million on financing activities, which included the net repayment of $7.1 million in long-term debt and $0.4 million in preferred stock dividends, offset by $1.9 million received through the exercise of stock options and warrants and a $0.6 million tax benefit related to the exercise of stock options.

 

We invested excess cash proceeds of $25.5 million in short-term investments consisting of a portfolio of periodic auction reset (PAR) securities, which have coupons that periodically reset to market interest rates at intervals ranging from 7 to 35 days. These PAR securities are being classified as short term investments and consist of AAA-rated tax-exempt municipal bonds. PAR securities are highly liquid and have minimal interest rate risk.

 

Subsequent Sources and Uses of Cash. In July 2005, the Fund invested $0.3 million in its fifth portfolio company, Moblize, which develops real time diagnostics and field optimization solutions for the oil and gas industry initially, and by using open-standards based technologies. Our limited partnership investment share was approximately $0.1 million.

 

On July 15, 2005, we sold $10.0 million of our Series D preferred stock to a group of private investors. The Series D preferred stock is perpetual and cumulative, is senior to our common stock and is

 

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convertible at any time into shares of our common stock at a price of $12.00 per share. The dividend on the Series D preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per annum.

 

On September 2, 2005, we purchased an additional 9.4% of our partially-owned subsidiary REX for $5.625 million and an additional 9.4% of COE for $1.875 million from JEX. As a result of these two purchases, our equity ownership interest in these partially-owned subsidiaries increased from 33.3% to 42.7% in REX and from 66.7% to 76.1% in COE.

 

As of September 7, 2005 we have approximately $29.1 million in cash, cash equivalents, and short term investments and have no debt. The Company currently has production of approximately 1,860 Mcf/d. Based on current prices and production rates, the Company anticipates EBITDAX of approximately $0.2 million per month.

 

Capital Budget. Our current capital expenditure budget for prospect generation, exploration and development activities for the remainder of calendar year 2005 is projected to be approximately $16 million, which calls for us to drill two offshore wells as the operator, six onshore wells as non-operator, and to be carried in another two offshore wells as a non-operator.

 

The onshore portion of our capital budget calls for us to invest approximately $2.0 million in the acquisition of additional Fayetteville Shale lease acreage, and approximately $4 million in drilling costs related to onshore prospects. In the offshore portion where we will participate as a non-operator, we will be fully carried in the Main Pass 221 and West Cameron 133 prospects.

 

In the offshore portion of our capital budget where COI will invest and operate, we will drill two prospects, Eugene Island 10 (our “Dutch” prospect) and Grand Isle 72 (our “Liberty” prospect). We expect to begin drilling our two offshore exploration wells prior to calendar year-end 2005 though the after-effects of Hurricane Katrina could significantly alter expected rig availability and timing. Contango’s combined capital commitment for both wells is estimated at $10 million, or $5 million per well. This represents a major increase in the risk profile of the Company which has never operated and which in the past has limited its dry hole risk exposure on any one well to approximately $1 million. Our estimated cost commitment could be significantly larger if we encounter difficultly in drilling these wells.

 

A majority of the projected $16 million capital commitment for prospect generation, exploration and development is concentrated in three prospects: our Fayetteville Shale play at $2 million and two offshore exploration prospects at $5 million each. Thus a total of $12 million will be risked on just three prospects. These significantly larger capital commitments greatly increase the potential risk and reward to the Company in comparison to our historical commitments made for prospects.

 

In addition to our capital expenditure budget for prospect generation, exploration and development activities, we expect to invest an additional $1.7 million at our Freeport LNG project for the remaining calendar year, which includes our share of the budgeted costs for Phase I construction as well as budgeted costs required for the engineering and development of a possible Phase II expansion. In addition, we expect to invest an additional $0.6 million in the Contango Capital Partners Fund, LP in order to fulfill our $1.5 million commitment made in January 2005.

 

We believe that our cash on hand, our cash equivalents, our short term investments and our anticipated cash flow from operations will be adequate to provide working capital for on-going operations, to fund our exploration and development programs, to maintain our 10% limited partnership interest in Freeport LNG, including any potential expansion in terminal capacity, to fund our remaining commitment to the Fund, and to satisfy general corporate needs. We may seek additional equity, sell assets or seek other financing to fund our exploration program and to take advantage of other opportunities that may become available. 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.

 

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Income Taxes. During the year ended June 30, 2005, we paid $7.974 million in estimated income taxes, in large part related to the sale of our south Texas natural gas and oil interests.

 

Contractual Obligations

 

Presented below are our contractual commitments for the periods indicated. See “Credit Facility” below for a description of our secured, reducing revolving bank line of credit.

 

          Fiscal Year Ending June 30,

     Total

   2006

   2007

   Thereafter

Office lease

   $ 159,518    $ 119,638    $ 39,880    $ —  

Office equipment

     1,227      1,227      —        —  
    

  

  

  

Total

   $ 160,745    $ 120,865    $ 39,880    $ —  
    

  

  

  

 

Credit Facility

 

The Company’s credit facility with Guaranty Bank, FSB is a secured, revolving line of credit, secured by the Company’s natural gas and oil reserves. As of June 30, 2005, the Company had no long-term debt outstanding. As of June 30, 2004, the Company’s long-term debt totaled $7.1 million, all of which was outstanding under Tranche A of the line of credit. The average interest rate on the Company’s long-term debt at June 30, 2004 was 3.3%.

 

Prior to the closing the sale of its south Texas natural gas and oil interests to Edge Petroleum Corporation in December 2004, the Company repaid all of its long-term debt outstanding under the facility. Our south Texas properties that were sold to Edge Petroleum constituted the bulk of the assets used to secure our existing bank line. Although the Company has no debt outstanding as of June 30, 2005, the revolving line of credit is being maintained and provides for a borrowing capacity of $0.1 million and matures on June 29, 2006. Borrowings will bear interest, at the Company’s option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, the Company pays a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability.

 

The hydrocarbon borrowing base is subject to semi-annual redetermination based primarily on the value of our proved reserves. The credit facility requires the maintenance of certain ratios, including those related to working capital, funded debt to EBITDAX, and debt service coverage, as defined in the credit agreements. Additionally, the credit agreements contain certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell assets, pay dividends and reacquire or otherwise acquire or redeem capital stock. Failure to maintain required financial ratios or comply with the credit facility’s covenants can result in a default and acceleration of all indebtedness under the credit facility. As of June 30, 2005, the Company was in compliance with its financial covenants, ratios and other provisions of its credit facility.

 

As of September 7, 2005 the Company had approximately $29.1 million in cash, cash equivalents, and short term investments and no debt.

 

Critical 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, and consolidation principles.

 

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

 

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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 the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows therefrom (See “Supplemental Oil and Gas Disclosures”) and the mark to market valuation of the Fund (See Footnote 7).

 

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, 2005 and 2004, 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, 2005, the Company had $3,985,775 in cash and cash equivalents, of which $3,209,237 was invested in highly liquid AAA-rated tax-exempt money market funds. Cash equivalents are considered to be all highly liquid debt investments having an original maturity of three months or less. As of June 30, 2004, the Company had cash and cash equivalents of $396,753.

 

Short Term Investments. As of June 30, 2005, the Company had $25,499,869 invested in a portfolio of periodic auction reset (“PAR”) securities, which have coupons that periodically reset to market interest rates at intervals ranging from 7 to 35 days. These PAR securities are being classified as short term investments and consist of AAA-rated tax-exempt municipal bonds. PAR securities are highly liquid and have minimal interest rate risk.

 

Marketable Equity Securities. All of the Company’s marketable securities were related to an investment in Cheniere Energy, Inc. common stock, which was sold in fiscal year 2004 resulting in a gain of $710,322 recognized under “Gain on Sale of Marketable Securities”.

 

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 footnote 5 for the calculations of basic and diluted net income (loss) per common share).

 

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

 

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

 

Consolidated Statements of Cash Flows. For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less when purchased to be cash equivalents. Significant transactions may occur which 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.

 

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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 was variable rate debt and, as such, approximated 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.

 

On July 1, 2003, the Company changed its accounting policy for amortizing and impairing the Company’s natural gas and oil properties from a well-by-well cost center basis to a field-by-field cost center basis. Management believes this policy is preferable in these circumstances to have 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. The Company determined that the cumulative effect of the change in accordance with APB Opinion No. 20 was immaterial to the consolidated financial statements.

 

In accordance with Statement of Financial Accounting Standards No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company classified our recent property sale to Edge Petroleum as discontinued operations. See Note 4 – Sale of Properties – Discontinued Operations of the Notes to Financial Statements included in Part II, Item 8. It is our intent, however, to remain an independent natural gas and oil company engaged in the exploration, production, and acquisition of natural gas and oil.

 

Principles of Consolidation. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries and affiliates, after elimination of all intercompany balances and transactions. Wholly-owned subsidiaries are fully consolidated. Exploration and development subsidiaries not wholly owned, such as 33.3% owned REX, 50% owned MOE, and 66.7% owned COE, each as of June 30, 2005, are not controlled by the Company and are proportionately consolidated. By agreement, REX, MOE and COE have disproportionate allocations of their profits and losses among the owners. Accordingly, the Company determines its income or losses from the ventures based on a hypothetical liquidation determination of how increases or decreases in the book value of the ventures’ net assets will ultimately affect the cash payments to the Company in the event of dissolution.

 

By agreement, since the Company was the only owner that contributed cash to REX and MOE, the Company consolidated 100% of the ventures’ net assets and results of operations until the ventures expended all of the Company’s initial cash contributions. Subsequent to that event, the owners’ share in the net assets of the ventures is based on their stated ownership percentages. By agreement, the owners in COE immediately share in the net assets of COE, including the Company’s initial cash contribution, based on their stated ownership percentages. The other owners of REX, MOE and COE contributed seismic data and related geological and geophysical services to the ventures.

 

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

 

Contango’s 32% ownership in CCPM and Contango’s 25% limited partnership interest in Contango Capital Partners, L.P. are accounted for using the equity method. Under the equity method, only Contango’s investment in and amounts due to and from the equity investee are included in the consolidated balance sheet.

 

Recent Accounting Pronouncements. The Financial Accounting Standards Board (“FASB”) has issued several new pronouncements, including Interpretation No. 46 (revised December 2003) (“FIN 46R”), “Consolidation of Variable Interest Entities, an interpretation of ARB 51”, Statement of Financial Accounting Standards No. 149 (“SFAS 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” and Statement of Financial Accounting Standards No. 150 (“SFAS 150”), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”.

 

The primary objectives of FIN 46R are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights (these entities are referred to as “variable interest entities” or “VIEs”) and how to determine if a business enterprise should consolidate the VIEs. This new model for consolidation applies to an entity for which either:

 

    The equity investors (if any) do not have a controlling financial interest; or

 

    The equity investment at risk is insufficient to finance the entity’s activities without receiving additional subordinated financial support from other parties.

 

In addition, FIN 46R requires that all enterprises with a significant variable interest in a VIE make additional disclosures regarding their relationship with the VIE. The adoption of FIN 46R had no effect on the Company’s financial statements.

 

SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS 133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149 is generally effective for contracts entered into or modified after June 20, 2003 (with limited exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 had no effect on the Company’s financial statements.

 

In July 2005, the FASB issued their proposed interpretation of FASB Statement No. 109, Accounting for Uncertain Tax Positions (“FSP FAS 109-1”). Their proposed interpretation seeks to reduce the significant diversity in practice associated with financial statement recognition and measurement in accounting for income taxes. As proposed, the Interpretation will become effective at the end of the first fiscal year ending after December 15, 2005. Management has not yet determined the effect that the Interpretation will have on the Company.

 

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS No. 3”, “Reporting Accounting Changes in Interim Financial Statements-An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005 and is required to be adopted by the Company in the first quarter of 2006.

 

In April 2005, the FASB issued Staff Position No. FAS 19-1, Accounting for Suspended Well Costs (“FSP FAS 19-1”). FSP FAS 19-1 amends Statement of Financial Accounting Standards No. 19 (“SFAS 19”), “Financial Accounting and Reporting by Oil and Gas Producing Companies”, to allow continued capitalization of exploratory well costs beyond one year from the date drilling was completed under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is

 

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making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP FAS 19-1 also amends SFAS No. 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the financial statements for annual and interim periods when there has been a significant change from the previous disclosure. The guidance in FSP FAS 19-1 is effective for the first reporting period beginning after April 4, 2005. The Company adopted the new requirements in its Form 10-K for the period ended June 30, 2005. The adoption of FSP FAS 19-1 did not have a material impact on the Company’s consolidated financial position or results of operations.

 

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) (“SFAS 123(R)”), “Share-Based Payment”. This statement requires the cost resulting from all share-based payment transactions be recognized in the financial statements at their fair value on the grant date. SFAS 123(R) is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. In April 2005, the Securities and Exchange Commission issued a rule that amends the date for compliance with SFAS 123(R). As a result, the Company will adopt this statement on July 1, 2006.

 

Stock-Based Compensation. Prior to the fiscal year-ended June 30, 2002, the Company accounted for employee stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”. Under the intrinsic method, compensation cost for stock options is measured as the excess, if any, of the fair value of the Company’s common stock at the date of the grant over the amount an employee must pay to acquire the common stock.

 

Effective July 1, 2001, the Company prospectively changed its method of accounting for employee stock-based compensation to the fair value based method prescribed in Statement of Financial Accounting Standards No. 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.

 

The Company has determined that the fair value method is preferable to the intrinsic value method previously applied. During the years ended June 30, 2005, 2004 and 2003, the Company recorded a charge of $385,193, $339,005, and $134,431 to general and administrative expense, respectively.

 

Derivative Instruments and Hedging Activities. Contango previously has entered into commodity derivatives contracts and fixed-price physical contracts to manage its exposure to natural gas and oil price volatility. Commodity derivatives contracts, which are usually placed with investment grade companies that the Company believes are minimal credit risk, may take the form of futures contracts, swaps or options. The natural gas and oil reference prices upon which these commodity derivatives contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.

 

The table below sets forth the Company’s hedging activities for the periods indicated:

 

    Year Ended June 30,

 
    2005

   2004

   2003

 

Mark-to-market reversal of prior period unrealized recognized loss (gain)

  $ —      $ 58,171    $ 125,674  

Net cash received (paid) from swap settlements/options purchased

    —        —        (5,776,461 )

Mark-to-market loss unrealized

    —        —        (58,171 )
   

  

  


Gain (loss) from hedging activities

  $ —      $ 58,171    $ (5,708,958 )
   

  

  


 

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Although the Company’s hedging transactions generally have been designed as economic hedges for a portion of future natural gas and oil production, the Company elected not to designate the derivative instruments as “hedges” under SFAS 133. As a result, gains and losses, representing changes in these derivative instruments’ mark-to-market fair values, were recognized in the Company’s earnings. The Company had no open commodity derivative contracts at June 30, 2005 and has a policy to hedge only through the purchase of puts.

 

Asset Retirement Obligation. The Company adopted Statement of Financial Accounting Standards 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. Activities related to the Company’s ARO during the year ended June 30, 2005 and 2004 are as follows:

 

     Year Ended June 30,

 
     2005

    2004

 

Initial ARO as of July 1

   $ 84,805     $ 191,664  

Liabilities incurred during period

     2,336       6,987  

Liabilities settled during period

     (87,839 )     (129,336 )

Accretion expense

     1,655       15,490  
    


 


Balance of ARO as of June 30

   $ 957     $ 84,805  
    


 


 

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 the spot prices applicable to natural gas and crude oil. Prices received for natural gas and oil are volatile and unpredictable and are beyond our control. For the year ended June 30, 2005, a 10% fluctuation in the prices received for natural gas and oil production would have had an approximate $1.6 million impact on our revenues.

 

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

 

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 Page 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

 

Within 90 days prior to the filing of this report, an evaluation was performed under the supervision and with the participation of the Company’s management, including the Chairman, President, Chief Executive Officer, and Chief Financial Officer and the Controller, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures over financial reporting. Based on that evaluation, the Company’s management, including the Chairman, President, Chief Executive Officer and Chief Financial Officer and Controller, concluded that the Company’s disclosure controls and procedures were effective in ensuring that material information relating to the Company with respect to the periods covered by this report

 

45


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were made known to them. There have been no significant changes in the Company’s internal controls or in other factors that could significantly affect internal controls and procedures subsequent to the date of that evaluation.

 

Item 9B. Other Information

 

None.

 

PART III

 

Item 10. Directors and Executive Officers of the Registrant

 

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 2005 Annual Meeting of Stockholders (the “Proxy Statement”) under the headings “Election of Directors”, “Executive Compensation” and “Section 16(a) Beneficial Ownership Reporting Compliance” 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, 2005.

 

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

 

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 “Executive Compensation” and is incorporated herein by reference.

 

Item 14. Principal Accountant Fees ands Services

 

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

 

PART IV

 

Item 15. Exhibits and Financial Statement Schedules

 

(a) Financial Statements and Schedules:

 

The financial statements are set forth in pages F-1 to F-7 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.

 

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(b) Exhibits:

 

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

 

Exhibit

Number


  

Description    


2.1    Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and REX Offshore Corporation, dated as of September 1, 2005. (27)
2.2    Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and COE Offshore, LLC dated as of September 1, 2005. (27)
3.1    Certificate of Incorporation of Contango Oil & Gas Company. (7)
3.2    Bylaws of Contango Oil & Gas Company. (7)
3.3    Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation. (7)
3.4    Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (15)
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. (19)
4.3    Certificate of Designations, Preferences and Relative Rights and Limitations for Series D Perpetual Cumulative Convertible Preferred Stock of Contango Oil & Gas Company. (26)
4.4    Securities Purchase Agreement, dated as of July 15, 2005, among Contango Oil & Gas Company and the Purchasers Named Therein. (26)
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. (12)
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)
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    Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (8)
10.10    First Amendment dated as of January 8, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (9)
10.11    Asset Purchase Agreement by and among Juneau Exploration, L.P. and Contango Oil & Gas Company dated January 4, 2002. (9)
10.12    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. (10)
10.13    Second Amendment dated as of February 13, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (11)
10.14    Waiver dated as of March 25, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (11)
10.15    Option Purchase Agreement between Contango Oil & Gas Company and Cheniere Energy, Inc. dated June 4, 2002. (13)
10.16    Waiver and Third Amendment dated as of April 26, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (14)

 

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10.17    Fourth Amendment dated as of September 9, 2002 to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (14)
10.18    Fifth Amendment, effective June 1, 2003, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (16)
10.19    Sixth Amendment, effective September 1, 2003, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (18)
10.20    Seventh Amendment, effective September 1, 2003, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (21)
10.21    Securities Purchase Agreement dated December 12, 2003 by and between Contango Oil & Gas Company and the Purchasers Named Therein. (19)
10.22    Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated February 27, 2003. (20)
10.23    Partnership Purchase Agreement among Contango Sundance, Inc., Contango Oil & Gas, Cheniere LNG, Inc. and Cheniere Energy, Inc. dated March 1, 2003. (20)
10.24    First Amendment, dated December 19, 2003, to Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated February 27, 2003. (20)
10.25    Eighth Amendment, effective February 13, 2004, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (22)
10.26    Ninth Amendment, effective July 29, 2004, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (23)
10.27    Tenth Amendment, effective September 23, 2004, to Credit Agreement between Contango Oil & Gas Company and Guaranty Bank, FSB, dated June 29, 2001. (25)
10.28    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. (24)
10.29    Limited Liability Company Agreement of Republic Exploration LLC dated August 24, 2000. (27)
10.30    Amendment to Limited Liability Company Agreement and Additional Agreements of Republic Exploration LLC dated as of September 1, 2005. (27)
10.31    Limited Liability Company Agreement of Contango Offshore Exploration LLC dated November 1, 2000. (27)
10.32    First Amendment to Limited Liability Company Agreement and Additional Agreements of Contango Offshore Exploration LLC dated as of September 1, 2005. (27)
10.33*    Contango Oil & Gas Company 1999 Stock Incentive Plan. †
10.34*    Amended No. 1 to Contango Oil & Gas Company 1999 Stock Incentive Plan dated as of March 7, 2001. †
14.1    Code of Ethics. (17)
21.1    List of Subsidiaries. †
23.1    Consent of W.D. Von Gonten & Co. †
23.2    Consent of Grant Thorton LLP. †
31.1    Certification required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. †
32.1    Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. †

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 September 27, 2000, as filed with the Securities and Exchange Commission on October 3, 2000.
7. 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.
8. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2001, as filed with the Securities and Exchange Commission on September 21, 2001.

 

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9. 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.
10. 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.
11. Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended March 31, 2002, dated May 2, 2002, as filed with the Securities and Exchange Commission.
12. 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.
13. 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.
14. Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2002, as filed with the Securities and Exchange Commission on September 26, 2002.
15. 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.
16. Filed as an exhibit to the Company’s report on Form 8-K, dated June 17, 2003, as filed with the Securities and Exchange Commission on June 18, 2003.
17. 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.
18. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2003, dated November 12, 2003, as filed with the Securities and Exchange Commission.
19. 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.
20. 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.
21. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended December 31, 2003, dated February 13, 2004, as filed with the Securities and Exchange Commission.
22. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2004, dated May 12, 2004, as filed with the Securities and Exchange Commission.
23. Filed as an exhibit to the Company’s annual report on Form 10-K for the fiscal year ended June 30, 2004, as filed with the Securities and Exchange Commission on September 27, 2004.
24. 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.
25. Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2004, dated November 12, 2004, as filed with the Securities and Exchange Commission.
26. 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.
27. 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.

 

SIGNATURES

 

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

 

CONTANGO OIL & GAS COMPANY

 

/s/ KENNETH R. PEAK


     

/s/ LESIA BAUTINA


Kenneth R. Peak

Chairman, Chief Executive Officer and Chief Financial Officer (principal executive officer and principal financial officer)

     

Lesia Bautina

Senior Vice President and Controller (principal accounting officer)

 

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Table of Contents

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

  September 13, 2005

/s/ JAY D. BREHMER


Jay D. Brehmer

  

Director

  September 13, 2005

/s/ JOSEPH S. COMPOFELICE


Joseph S. Compofelice

  

Director

  September 13, 2005

/s/ DARRELL W. WILLIAMS


Darrell W. Williams

  

Director

  September 13, 2005

 

50


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CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

     Page

Report of Independent Registered Public Accounting Firm

   F-2

Consolidated Balance Sheets, June 30, 2005 and 2004

   F-3

Consolidated Statements of Operations for the Years Ended June 30, 2005, 2004 and 2003

   F-5

Consolidated Statements of Cash Flows for the Years Ended June 30, 2005, 2004 and 2003

   F-6

Consolidated Statements of Shareholders’ Equity for the Years Ended June 30, 2005, 2004 and 2003

   F-7

Notes to Consolidated Financial Statements

   F-8

Supplemental Oil and Gas Disclosures

   F-26

Quarterly Results of Operations

   F-30

 

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, 2005 and 2004, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended June 30, 2005. 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. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 consolidated 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2005, in conformity with accounting principles generally accepted in the United States of America.

 

GRANT THORNTON LLP
Houston, Texas
September 2, 2005

 

F-2


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

     June 30,

 
     2005

    2004

 
ASSETS                 

CURRENT ASSETS:

                

Cash and cash equivalents

   $ 3,985,775     $ 396,753  

Short-term investments

     25,499,869       —    

Accounts receivable, net

     1,423,094       4,715,748  

Other

     302,926       139,778  
    


 


Total current assets

     31,211,664       5,252,279  
    


 


PROPERTY AND EQUIPMENT:

                

Natural gas and oil properties, successful efforts method of accounting:

                

Proved properties

     4,666,048       54,850,979  

Unproved properties, not being amortized

     7,789,306       7,540,678  

Furniture and equipment

     197,949       184,508  

Accumulated depreciation, depletion and amortization

     (1,328,567 )     (27,282,035 )
    


 


Total property, plant and equipment

     11,324,736       35,294,130  
    


 


OTHER ASSETS:

                

Cash and other assets held by affiliates

     1,067,263       779,361  

Investment in Freeport LNG project

     3,006,751       2,333,333  

Investment in Contango Venture Capital Corporation

     2,274,356       500,000  

Deferred income tax asset

     4,462,329       1,188,407  

Facility fee

     —         157,579  

Other

     5,822       5,822  
    


 


Total other assets

     10,816,521       4,964,502  
    


 


TOTAL ASSETS

   $ 53,352,921     $ 45,510,911  
    


 


 

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

 

F-3


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

 

     June 30,

 
     2005

    2004

 
LIABILITIES AND SHAREHOLDERS’ EQUITY                 

CURRENT LIABILITIES:

                

Accounts payable

   $ 435,661     $ 810,360  

Accrued exploration and development

     85,608       950,175  

Income taxes payable

     1,658,548       240,758  

G&A accrued liabilities

     189,823       207,631  

Other accrued liabilities

     3,271       11,651  
    


 


Total current liabilities

     2,372,911       2,220,575  
    


 


LONG-TERM DEBT

     —         7,089,000  

ASSET RETIREMENT OBLIGATION

     957       84,805  

SHAREHOLDERS’ EQUITY:

                

Convertible preferred stock, 6%, Series C, $0.04 par value, 4,000 shares authorized, 1,400 shares issued and outstanding at June 30, 2005, liquidation preference of $7,000,000 at $5,000 per share; 1,600 shares issued and outstanding at June 30, 2004, liquidation preference of $8,000,000 at $5,000 per share

     56       64  

Common stock, $0.04 par value, 50,000,000 shares authorized, 15,997,809 shares issued and 13,422,809 shares outstanding at June 30, 2005, 14,885,700 shares issued and 12,310,700 shares outstanding at June 30, 2004

     639,910       595,428  

Additional paid-in capital

     32,800,077       29,979,965  

Treasury stock at cost (2,575,000 shares)

     (6,180,000 )     (6,180,000 )

Retained earnings

     23,719,010       11,721,074  
    


 


Total shareholders’ equity

     50,979,053       36,116,531  
    


 


TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

   $ 53,352,921     $ 45,510,911  
    


 


 

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

 

 

F-4


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

 

     Year Ended June 30,

 
     2005

    2004

    2003

 

REVENUES:

                        

Natural gas and oil sales

   $ 4,330,440     $ 194,983     $ 228,062  

Gain (loss) from hedging activities

     —         58,171       (5,708,958 )
    


 


 


Total revenues

     4,330,440       253,154       (5,480,896 )
    


 


 


EXPENSES:

                        

Operating expenses

     506,943       142,809       112,326  

Exploration expenses

     6,607,049       8,847,533       12,640,878  

Depreciation, depletion and amortization

     1,232,624       40,817       26,773  

Impairment of natural gas and oil properties

     236,537       42,995       181,610  

General and administrative expense

     3,570,957       2,695,592       2,063,503  
    


 


 


Total expenses

     12,154,110       11,769,746       15,025,090  
    


 


 


LOSS FROM CONTINUING OPERATIONS BEFORE OTHER INCOME AND INCOME TAXES

     (7,823,670 )     (11,516,592 )     (20,505,986 )

OTHER INCOME:

                        

Interest expense

     (71,506 )     (362,127 )     (710,587 )

Interest income

     431,803       38,182       30,359  

Gain on sale of marketable securities

     —         710,322       451,500  

Gain on sale of assets and other

     705,147       6,187,740       39,230  
    


 


 


LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES

     (6,758,226 )     (4,942,475 )     (20,695,484 )

Benefit for income taxes

     2,350,257       1,788,359       7,243,419  
    


 


 


LOSS FROM CONTINUING OPERATIONS

     (4,407,969 )     (3,154,116 )     (13,452,065 )

DISCONTINUED OPERATIONS (Note 4):

                        

Discontinued operations, net of income taxes

     16,825,905       10,854,465       9,116,040  
    


 


 


NET INCOME (LOSS)

     12,417,936       7,700,349       (4,336,025 )

Preferred stock dividends

     420,000       620,000       600,000  
    


 


 


NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK

   $ 11,997,936     $ 7,080,349     $ (4,936,025 )
    


 


 


NET INCOME (LOSS) PER SHARE:

                        

Basic

                        

Continuing operations

   $ (0.37 )   $ (0.36 )   $ (1.54 )

Discontinued operations

     1.29       1.04       1.00  
    


 


 


Total

   $ 0.92     $ 0.68     $ (0.54 )
    


 


 


Diluted

                        

Continuing operations

   $ (0.37 )   $ (0.36 )   $ (1.54 )

Discontinued operations

     1.29       1.04       1.00  
    


 


 


Total

   $ 0.92     $ 0.68     $ (0.54 )
    


 


 


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:

                        

Basic

     13,089,332       10,484,078       9,129,169  
    


 


 


Diluted

     13,089,332       10,484,078       9,129,169  
    


 


 


 

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

 

F-5


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     Year Ended June 30,

 
     2005

    2004

    2003

 

CASH FLOWS FROM OPERATING ACTIVITIES:

                        

Loss from continuing operations

   $ (4,407,969 )   $ (3,154,116 )   $ (13,452,065 )

Plus income from discontinued operations, net of income taxes

     16,825,905       10,854,465       9,116,040  
    


 


 


Net income (Loss)

     12,417,936       7,700,349       (4,336,025 )

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

                        

Depreciation, depletion and amortization

     2,815,982       6,989,428       8,787,794  

Impairment of natural gas and oil properties

     236,537       42,995       181,610  

Exploration expenditures

     4,875,506       6,073,120       6,351,117  

Deferred income taxes

     (3,273,922 )     (533,605 )     (4,345,888 )

Gain on sale of assets and other

     (16,993,441 )     (7,882,026 )     (490,730 )

Unrealized hedging gain

     —         (58,171 )     (64,423 )

Stock-based compensation

     385,193       339,005       134,431  

Tax benefit from exercise of stock options

     591,226       86,778       7,292  

Changes in operating assets and liabilities:

                        

Decrease (increase) in accounts receivable and other

     3,341,701       1,272,822       (819,326 )

(Increase) in marketable securities

     —         —         (225,000 )

Decrease (increase) in prepaid insurance

     (10,498 )     (22,301 )     118,713  

(Decrease) in accounts payable

     (165,032 )     (391,551 )     (594,933 )

Increase (decrease) in other accrued liabilities

     (731,004 )     11,652       (211,585 )

Increase (decrease) in income taxes payable

     1,417,790       (493,554 )     (306,476 )

Other

     550       (15,218 )     (92,053 )
    


 


 


Net cash provided by operating activities

     4,908,524       13,119,723       4,094,518  
    


 


 


CASH FLOWS FROM INVESTING ACTIVITIES:

                        

Natural gas and oil exploration and development expenditures

     (9,091,333 )     (12,150,210 )     (8,595,940 )

Natural gas and oil exploration and development reimbursements, net of additions

     1,461,053       —         —    

Increase in net investment in affiliates

     (287,902 )     5,295       850,000  

Investment in Freeport LNG Project

     (673,418 )     (1,483,333 )     (100,000 )

Purchase of short-term investments

     (25,499,869 )     —         —    

Additions to furniture and equipment

     (16,412 )     (58,120 )     (16,560 )

(Increase) decrease in advances to operators

     (509,662 )     157,350       853,347  

Investment in Contango Venture Capital Corporation

     (1,023,668 )     (500,000 )     —    

Purchase of marketable equity securities

     —         (375,000 )     —    

Proceeds from sales of marketable equity securities

     —         1,761,822       —    

Purchase of proved producing reserves

     —         —         (2,599,485 )

Sale/Acquisition costs

     (168,686 )     (5,281 )     (3,066 )

Proceeds from the sale of assets

     40,131,428       7,766,379       —    
    


 


 


Net cash provided (used) by investing activities

     4,321,531       (4,881,098 )     (9,611,704 )
    


 


 


CASH FLOWS FROM FINANCING ACTIVITIES:

                        

Borrowings under credit facility

     2,200,000       22,229,028       29,670,000  

Repayments under credit facility

     (9,289,000 )     (37,490,028 )     (26,270,000 )

Proceeds from preferred equity issuances

     —         7,554,614       —    

Preferred stock dividends

     (420,000 )     (620,000 )     (600,000 )

Repurchase/cancellation of stock options and warrants

     —         (757,498 )     —    

Proceeds from exercised options and warrants

     1,888,167       1,075,769       433,333  

Debt issue costs

     (20,200 )     (52,999 )     (223,750 )
    


 


 


Net cash provided (used) in financing activities

     (5,641,033 )     (8,061,114 )     3,009,583  
    


 


 


NET INCREASE IN CASH AND CASH EQUIVALENTS

     3,589,022       177,511       (2,507,603 )

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

     396,753       219,242       2,726,845  
    


 


 


CASH AND CASH EQUIVALENTS, END OF PERIOD

   $ 3,985,775     $ 396,753     $ 219,242  
    


 


 


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

                        

Cash paid for taxes

   $ 7,974,387     $ 4,781,239     $ 2,549,788  
    


 


 


Cash paid for interest

   $ 83,696     $ 386,743     $ 711,808  
    


 


 


 

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

 

F-6


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

 

     Preferred Stock

    Common Stock

  

Paid-in

Capital


   

Treasury

Stock


   

Retained

Earnings


   

Total

Stockholders’

Equity


 
     Shares

    Amount

    Shares

   Amount

        

Balance at June 30, 2002

   7,500     $ 300     9,043,282    $ 464,732    $ 21,236,701     $ (6,180,000 )   $ 9,576,750     $ 25,098,483  

Exercise of stock options and warrants

   —         —       252,794      8,667      424,666       —         —         433,333  

Tax benefit from exercise of stock options

   —         —       —        —        7,292       —         —         7,292  

Expense of stock options

   —         —       —        —        134,431       —         —         134,431  

Net loss

   —         —       —        —        —                 (4,336,025 )     (4,336,025 )

Preferred stock dividends

   —         —       —        —        —         —         (600,000 )     (600,000 )
    

 


 
  

  


 


 


 


Balance at June 30, 2003

   7,500     $ 300     9,296,076    $ 473,399    $ 21,803,090     $ (6,180,000 )   $ 4,640,725     $ 20,737,514  
    

 


 
  

  


 


 


 


Exercise of stock options and warrants

   —         —       518,750      20,750      1,055,019       —         —         1,075,769  

Tax benefit from exercise of stock options

   —         —       —        —        86,778       —         —         86,778  

Expense of stock options

   —         —       —        —        339,005       —         —         339,005  

Cashless exercise of stock options and warrants

   —         —       359,510      15,824      (15,824 )     —         —         —    

Repurchase/cancellation of stock options and warrants

   —         —       —        —        (757,498 )     —         —         (757,498 )

Conversion of Series A preferred stock and Series B preferred stock to common stock

   (7,500 )     (300 )   2,136,364      85,455      (85,155 )     —         —         —    

Issuance of Series C preferred stock

   1,600       64     —        —        7,554,550       —         —         7,554,614  

Net income

   —         —       —        —        —         —         7,700,349       7,700,349  

Preferred stock dividends

   —         —       —        —        —         —         (620,000 )     (620,000 )
    

 


 
  

  


 


 


 


Balance at June 30, 2004

   1,600     $ 64     12,310,700    $ 595,428    $ 29,979,965     $ (6,180,000 )   $ 11,721,074     $ 36,116,531  
    

 


 
  

  


 


 


 


Exercise of stock options and warrants

   —         —       747,584      29,902      1,858,265       —         —         1,888,167  

Tax benefit from exercise of stock options

   —         —       —        —        591,226       —         —         591,226  

Cashless exercise of stock options and warrants

   —         —       197,859      7,913      (7,913 )     —         —         —    

Partial conversion of Series C preferred stock to common stock

   (200 )     (8 )   166,666      6,667      (6,659 )     —         —         —    

Expense of stock options

   —         —       —        —        385,193       —         —         385,193  

Net income

   —         —       —        —        —         —         12,417,936       12,417,936  

Preferred stock dividends

   —         —       —        —        —         —         (420,000 )     (420,000 )
    

 


 
  

  


 


 


 


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  
    

 


 
  

  


 


 


 


 

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

 

F-7


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. Organization and Business

 

Contango is a Houston-based, independent natural gas and oil company. The Company’s core business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico and onshore along the Gulf Coast. As a recent addition to our business, we will begin acting as an operator on certain offshore prospects through our wholly-owned subsidiary, Contango Operators, Inc. (“COI”). The Company also owns a 10% interest in a limited partnership formed to develop an LNG receiving terminal in Freeport, Texas, and holds investments in the alternative energy venture capital market with a focus on environmentally preferred energy technologies.

 

2. Summary of Significant Accounting Policies

 

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

 

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. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows therefrom (See “Supplemental Oil and Gas Disclosures”) and the mark to market valuation of the Fund (See Footnote 7).

 

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, 2005 and 2004, 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, 2005, the Company had $3,985,775 in cash and cash equivalents, of which $3,209,237 was invested in highly liquid AAA-rated tax-exempt money market funds. Cash equivalents are considered to be all highly liquid debt investments having an original maturity of three months or less. As of June 30, 2004, the Company had cash and cash equivalents of $396,753.

 

Short Term Investments. As of June 30, 2005, the Company had $ 25,499,869 invested in a portfolio of periodic auction reset (“PAR”) securities, which have coupons that periodically reset to market interest rates at intervals ranging from 7 to 35 days. These PAR securities are being classified as short term investments and consist of AAA-rated tax-exempt municipal bonds. PAR securities are highly liquid and have minimal interest rate risk.

 

Marketable Equity Securities. As part of the formation of Freeport LNG Development, L.P., Cheniere Energy, Inc. (“Cheniere”) granted Contango warrants to purchase 300,000 shares of Cheniere common stock. In June and September 2003, Contango exercised the warrants, purchasing 300,000 shares of Cheniere common stock. All of the Company’s marketable securities related to an investment in Cheniere common stock, were sold in fiscal year 2004 resulting in a gain of $710,322 recognized under “Gain on Sale of Marketable Securities”.

 

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

 

F-8


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

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 5 – Net Income (Loss) Per Common Share for the calculations of basic and diluted net income (loss) per common share.

 

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

 

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

 

Consolidated Statements of Cash Flows. For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less when purchased to be cash equivalents. Significant transactions may occur which 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 was variable rate debt and, as such, approximated 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.

 

On July 1, 2003, the Company changed its accounting policy for amortizing and impairing the Company’s natural gas and oil properties from a well-by-well cost center basis to a field-by-field cost center basis. Management believes this policy is preferable in these circumstances to have 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. The Company determined that the cumulative effect of the change in accordance with APB Opinion No. 20 was immaterial to the consolidated financial statements.

 

F-9


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

In accordance with Statement of Financial Accounting Standards No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company classified our recent property sale to Edge Petroleum as discontinued operations. See Note 4 – Sale of Properties – Discontinued Operations. It is our intent, however, to remain an independent natural gas and oil company engaged in the exploration, production, and acquisition of natural gas and oil.

 

Principles of Consolidation. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries and affiliates, after elimination of all intercompany balances and transactions. Wholly-owned subsidiaries are fully consolidated. Exploration and development subsidiaries not wholly owned, such as 33.3% owned REX, 50% owned MOE, and 66.7% owned COE, each as of June 30, 2005, are not controlled by the Company and are proportionately consolidated. By agreement, REX, MOE and COE have disproportionate allocations of their profits and losses among the owners. Accordingly, the Company determines its income or losses from the ventures based on a hypothetical liquidation determination of how increases or decreases in the book value of the ventures’ net assets will ultimately affect the cash payments to the Company in the event of dissolution.

 

By agreement, since the Company was the only owner that contributed cash to REX and MOE, the Company consolidated 100% of the ventures’ net assets and results of operations until the ventures expended all of the Company’s initial cash contributions. Subsequent to that event, the owners’ share in the net assets of the ventures is based on their stated ownership percentages. By agreement, the owners in COE immediately share in the net assets of COE, including the initial Company cash contribution, based on their stated ownership percentages. The other owners of REX, MOE and COE contributed seismic data and related geological and geophysical services to the ventures.

 

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

 

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

 

Recent Accounting Pronouncements. The Financial Accounting Standards Board (“FASB”) has issued several new pronouncements, including Interpretation No. 46 (revised December 2003) (“FIN 46R”), “Consolidation of Variable Interest Entities, an interpretation of ARB 51”, Statement of Financial Accounting Standards No. 149 (“SFAS 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” and Statement of Financial Accounting Standards No. 150 (“SFAS 150”), “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”.

 

The primary objectives of FIN 46R are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights (these entities are referred to as “variable interest entities” or “VIEs”) and how to determine if a business enterprise should consolidate the VIEs. This new model for consolidation applies to an entity for which either:

 

    The equity investors (if any) do not have a controlling financial interest; or

 

    The equity investment at risk is insufficient to finance the entity’s activities without receiving additional subordinated financial support from other parties.

 

F-10


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

In addition, FIN 46R requires that all enterprises with a significant variable interest in a VIE make additional disclosures regarding their relationship with the VIE. The adoption of FIN 46R had no effect on the Company’s financial statements.

 

SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS 133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149 is generally effective for contracts entered into or modified after June 20, 2003 (with limited exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 had no effect on the Company’s financial statements.

 

In July 2005, the FASB issued their proposed interpretation of FASB Statement No. 109, Accounting for Uncertain Tax Positions (“FSP FAS 109-1”). Their proposed interpretation seeks to reduce the significant diversity in practice associated with financial statement recognition and measurement in accounting for income taxes. As proposed, the Interpretation will become effective at the end of the first fiscal year ending after December 15, 2005. Management has not yet determined the effect that the Interpretation will have on the Company.

 

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” which replaces Accounting Principles Board Opinions No. 20 “Accounting Changes” and SFAS No. 3”, “Reporting Accounting Changes in Interim Financial Statements-An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005 and is required to be adopted by the Company in the first quarter of 2006.

 

In April 2005, the FASB issued Staff Position No. FAS 19-1, Accounting for Suspended Well Costs (“FSP FAS 19-1”). FSP FAS 19-1 amends Statement of Financial Accounting Standards No. 19 (“SFAS 19”), “Financial Accounting and Reporting by Oil and Gas Producing Companies”, to allow continued capitalization of exploratory well costs beyond one year from the date drilling was completed under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP FAS 19-1 also amends SFAS No. 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the financial statements for annual and interim periods when there has been a significant change from the previous disclosure. The guidance in FSP FAS 19-1 is effective for the first reporting period beginning after April 4, 2005. The Company adopted the new requirements in its Form 10-K for the period ended June 30, 2005. The adoption of FSP FAS 19-1 did not have a material impact on the Company’s consolidated financial position or results of operations.

 

In December 2004, the FASB issued SFAS No. 123 (revised 2004) or SFAS No. 123(R), Share-Based Payment. This statement requires the cost resulting from all share-based payment transactions be recognized in the financial statements at their fair value on the grant date. SFAS No. 123(R) is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. In April 2005, the Securities and Exchange Commission issued a rule that amends the date for compliance with SFAS No. 123(R). As a result, the Company will adopt this statement on July 1, 2006.

 

Stock-Based Compensation. Prior to the fiscal year-ended June 30, 2002, the Company accounted for employee stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”. Under the intrinsic method, compensation cost for stock options is measured as the excess, if any, of the fair value of the Company’s common stock at the date of the grant over the amount an employee must pay to acquire the common stock.

 

F-11


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

Effective July 1, 2001, the Company prospectively changed its method of accounting for employee stock-based compensation to the fair value based method prescribed in Statement of Financial Accounting Standards No. 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.

 

The Company has determined that the fair value method is preferable to the intrinsic value method previously applied. During the years ended June 30, 2005, 2004 and 2003, the Company recorded a charge of $385,193, $339,005, and $134,431 to general and administrative expense, respectively.

 

Derivative Instruments and Hedging Activities. Contango previously has entered into commodity derivatives contracts and fixed-price physical contracts to manage its exposure to natural gas and oil price volatility. Commodity derivatives contracts, which are usually placed with investment grade companies that the Company believes are minimal credit risk, may take the form of futures contracts, swaps or options. The natural gas and oil reference prices upon which these commodity derivatives contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.

 

The table below sets forth the Company’s hedging activities for the periods indicated:

 

     Year Ended June 30,

 
     2005

   2004

   2003

 

Mark-to-market reversal of prior period unrealized recognized loss (gain)

   $  —      $ 58,171    $ 125,674  

Net cash received (paid) from swap settlements/options purchased

     —        —        (5,776,461 )

Mark-to-market loss unrealized

     —        —        (58,171 )
    

  

  


Gain (loss) from hedging activities

   $ —      $ 58,171    $ (5,708,958 )
    

  

  


 

Although the Company’s hedging transactions generally have been designed as economic hedges for a portion of future natural gas and oil production, the Company elected not to designate the derivative instruments as “hedges” under SFAS 133. As a result, gains and losses, representing changes in these derivative instruments’ mark-to-market fair values, were recognized in the Company’s earnings. The Company had no open commodity derivative contracts at June 30, 2005 and has a policy to hedge only through the purchase of puts.

 

F-12


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

Asset Retirement Obligation. The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”, (“SFAS 143”), as of July 1, 2002. SFAS 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. Activities related to the Company’s ARO during the year ended June 30, 2005 and 2004 are as follows:

 

     Year Ended June 30,

 
     2005

    2004

 

Initial ARO as of July 1

   $ 84,805     $ 191,664  

Liabilities incurred during period

     2,336       6,987  

Liabilities settled during period

     (87,839 )     (129,336 )

Accretion expense

     1,655       15,490  
    


 


Balance of ARO as of June 30

   $ 957     $ 84,805  
    


 


 

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 prospects 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; 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.

 

4. Sale of Properties - Discontinued Operations

 

In December 2004 the Company completed the sale of the majority of its south Texas natural gas and oil interests to Edge Petroleum Corporation for $50 million. The sale was approved by a majority of the Company’s stockholders at a Special Meeting of Stockholders on December 29, 2004. Approximately 16 billion cubic feet per day equivalent (“Bcfe/d”) of proven reserves were sold having a pre-tax net present value when using a 10% discount rate as of June 30, 2004 of $54.3 million. Pre-tax proceeds after netting adjustments were $40.1 million. Adjustments were made for net revenues that Contango received for production occurring after July 1, 2004, the effective date of sale, up to the post-closing date of March 29, 2005. The Company recognized a gain on sale of $16.3 million for the year ended June 30, 2005. Our sale of assets to Edge Petroleum has been classified as discontinued operations in our financial statements for all periods presented.

 

In accordance with Statement of Financial Accounting Standards No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company classified our recent property sale to Edge Petroleum as discontinued operations. It is our intent however, to remain an independent natural gas and oil company engaged in the exploration, production, and acquisition of natural gas and oil.

 

In September 2003, the Company completed the sale of certain reserves in Brooks County, Texas for $5.0 million and recorded a gain of approximately $1.0 million for the year ended June 30, 2004. Proved reserves were 1.5 Bcfe and accounted for approximately $5.0 million of the Company’s discounted present value at 10% per annum as of June 30, 2003. The sale of the Brooks County reserves has been reclassified as discontinued operations since these reserves were part of our original south Texas natural gas and oil interests.

 

F-13


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

The summarized financial results for discontinued operations for each of the periods ended June 30 are as follows:

 

     Twelve Months Ended June 30,

 
     2005

    2004

    2003

 

Operating Results:

                        

Revenues

   $ 11,936,266     $ 27,434,831     $ 33,691,064  

Operating expenses

     (728,283 )     (3,745,376 )     (5,624,128 )

Depreciation expenses

     (1,583,358 )     (6,948,611 )     (8,761,021 )

Exploration expenses

     (26,911 )     (1,025,631 )     (5,281,238 )

Gain on sale of discontinued operations

     16,288,294       983,964       —    
    


 


 


Gain before income taxes

   $ 25,886,008     $ 16,699,177     $ 14,024,677  

Provision for income taxes

     (9,060,103 )     (5,844,712 )     (4,908,637 )
    


 


 


Gain from discontinued operations, net of income taxes

   $ 16,825,905     $ 10,854,465     $ 9,116,040  
    


 


 


 

F-14


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

5. Net Income (Loss) Per Common Share

 

A reconciliation of the components of basic and diluted net income (loss) per common share for the fiscal years ended June 30, 2005, 2004 and 2003 is presented below:

 

     Year Ended June 30, 2005

 
    

Net

Income (Loss)


    Shares

    Per
Share


 

Loss from continuing operations including preferred dividends

   $ (4,827,969 )   13,089,332     $ (0.37 )

Discontinued operations, net of income taxes

     16,825,905     13,089,332       1.29  
    


 

 


Basic Earnings per Share:

                      

Net income

   $ 11,997,936     13,089,332     $ 0.92  
    


 

 


Effect of Potential Dilutive Securities:

                      

Stock options and warrants

     —       ( a)        

Series C preferred stock

     ( a)   ( a)        
    


 

 


Loss from continuing operations

   $ (4,827,969 )   13,089,332     $ (0.37 )

Discontinued operations, net of income taxes

     16,825,905     13,089,332       1.29  
    


 

 


Diluted Earnings per Share:

                      

Net income

   $ 11,997,936     13,089,332     $ 0.92  
    


 

 


Anti-dilutive Securities:

                      

Shares assumed not issued from options to purchase common shares as income from continuing operations was in a loss position for the period

   $ —       1,301,000     $ 6.38  

Series C Preferred Stock

   $ 420,000     1,166,667     $ 0.36  

(a) Anti-dilutive.

 

     Year Ended June 30, 2004

 
    

Net

Income (Loss)


    Shares

    Per
Share


 

Loss from continuing operations including preferred dividends

   $ (3,774,116 )   10,484,078     $ (0.36 )

Discontinued operations, net of income taxes

     10,854,465     10,484,078       1.04  
    


 

 


Basic Earnings per Share:

                      

Net income

   $ 7,080,349     10,484,078     $ 0.68  
    


 

 


Effect of Potential Dilutive Securities:

                      

Stock options and warrants

     —       ( a)        

Series A preferred stock

     ( a)   ( a)        

Series B preferred stock

     ( a)   ( a)        

Series C preferred stock

     ( a)   ( a)        
    


 

 


Loss from continuing operations

   $ (3,774,116 )   10,484,078     $ (0.36 )

Discontinued operations, net of income taxes

     10,854,465     10,484,078       1.04  
    


 

 


Diluted Earnings per Share:

                      

Net income

   $ 7,080,349     10,484,078     $ 0.68  
    


 

 


Anti-dilutive Securities:

                      

Shares assumed not issued from options to purchase common shares as income from continuing operations was in a loss position for the period

   $ —       1,966,521     $ 3.66  

Series A Preferred Stock

   $ 117,777     592,896     $ 0.20  

Series B Preferred Stock

   $ 235,556     673,746     $ 0.35  

Series C Preferred Stock

   $ 266,667     733,330     $ 0.36  

(a) Anti-dilutive.

 

F-15


Table of Contents

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)

 

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

 

     Year Ended June 30, 2003

 
    

Net

Income (Loss)


    Shares

    Per
Share


 

Loss from continuing operations including preferred dividends

   $ (14,052,065 )   9,129,169     $ (1.54 )

Discontinued operations, net of income taxes

     9,116,040     9,129,169       1.00  
    


 

 


Basic Earnings per Share:

                      

Net (Loss)

   $ (4,936,025 )   9,129,169     $ (0.54 )
    


 

 


Effect of Potential Dilutive Securities:

                      

Stock options and warrants

     —       ( a)        

Series A preferred stock

     ( a)   ( a)        

Series B preferred stock

     ( a)   ( a)        
    


 

 


Loss from continuing operations

   $ (14,052,065 )   9,129,169     $ (1.54 )

Discontinued operations, net of income taxes

     9,116,040     9,129,169       1.00  
    


 

 


Diluted Earnings per Share:

                      

Net (Loss)

   $ (4,936,025 )   9,129,169     $ (0.54 )
    


 

 


Anti-dilutive Securities:

                      

Shares assumed not issued f