UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

 

Commission file number 001-16317

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

 

 

3700 Buffalo Speedway, Suite 960

Houston, Texas 77098

(Address of principal executive offices)

 

(713) 960-1901

(Registrant’s telephone number, including area code)

 

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

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ

 

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

 

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

 

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

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

(Do not check if a smaller reporting company)

 

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

 

At December 31, 2007, the aggregate market value of the registrant’s common stock held by non-affiliates (based upon the closing sale price of shares of such common stock as reported on the American Stock Exchange) was $649,840,517. As of August 22, 2008, there were 16,824,246 shares of the registrant’s common stock outstanding.

 

Documents Incorporated by Reference

 

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

 

 

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

 

ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED JUNE 30, 2008

 

TABLE OF CONTENTS

 

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

 

Some of the statements made in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. These include such matters as:

 

 

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

 

 

 

You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events. See the information under the heading “Risk Factors” referred to on page 14 of this report for some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in forward-looking statements.

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

 

 

Contango is a Houston-based, independent natural gas and oil company. The Company’s business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico. Contango Operators, Inc. (“COI”) and Contango Resources Company (“CRC”), our wholly-owned subsidiaries, act as operator on certain offshore prospects.

 

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

 

Funding exploration prospects generated by Juneau Exploration, L.P., our alliance partner.  We depend totally upon our alliance partner, Juneau Exploration, L.P. (“JEX”), for prospect generation expertise. JEX is experienced and has a successful track record in exploration.

 

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

 

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

 

Sale of proved properties.  From time-to-time as part of our business strategy, we have sold and in the future expect to continue to sell some or a substantial portion of our proved reserves and assets to capture current value, using the sales proceeds to further our offshore exploration activities. Since its inception, the Company has sold approximately $484 million worth of natural gas and oil properties, and views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, and as a source of funds for potentially higher rate of return natural gas and oil exploration opportunities.

 

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

 

Structuring transactions to share risk.  JEX, our alliance partner, shares in the upfront costs and the risk of our exploration prospects.

 

Structuring incentives to drive behavior.  We believe that equity ownership aligns the interests of our partners, employees, and stockholders. Our directors and executive officers beneficially own or have voting control over approximately 23.1% of our common stock.

 

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

 

Contango directly and through REX and COE conducts exploration activities in the Gulf of Mexico. As of August 22, 2008, Contango, through its wholly-owned subsidiaries, COI and CRC, and its partially-owned subsidiaries, REX and COE, had an interest in 67 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.

 

As of June 30, 2008, Contango owned a 32.3% equity interest in REX and a 65.6% equity interest in COE, both of which were formed for the purpose of generating exploration opportunities in the Gulf of Mexico. See Exhibit 21.2 for an organizational chart of our subsidiaries. These companies focus on identifying prospects, acquiring leases at federal and state lease sales and then selling the prospects to third parties, including Contango, subject to timed drilling obligations plus retained reversionary interests in favor of REX and COE.

 

Republic Exploration LLC (REX)

 

Effective April 1, 2008, the Company sold a portion of its ownership interest in REX to an existing member of REX for approximately $0.8 million. As a result of the sale, the Company’s equity ownership interest in REX has decreased to 32.3%.

 

On April 3, 2008, the members of REX entered into an Amended and Restated Limited Liability Company Agreement (the “REX LLC Agreement”), effective as of April 1, 2008, to, among other things, distribute REX’s interest in Dutch and Mary Rose to the individual members of REX or their designees. In connection with this distribution, REX repaid in full all amounts owing by REX to a private investment firm under a $50.0 million demand promissory note with such private investment firm (the “REX Demand Note”), and all security interests and other liens granted in favor of such private investment firm as security for the obligations under the REX Demand Note have been released and terminated. The Company’s portion of such repayment was approximately $22.5 million.

 

On March 12, 2008, the Company announced that its wildcat exploration well at High Island A198, a REX prospect, was determined to be a dry hole, at a cost of approximately $4.2 million. The well has been plugged and abandoned.

 

West Delta 36 and Eugene Island 113-B, two REX prospects, are operated by a third party. The Company depends on third-party operators for the operation and maintenance of these production platforms. On March 7, 2008, REX elected to convert its 3.67% overriding royalty interest in West Delta 36 to an undivided 25% working interest, sometimes referred to herein as “WI”. As of August 21, 2008, West Delta 36, in which REX has a 20.0% net revenue interest, sometimes referred to herein as “NRI”, was producing at a rate of approximately 9.7 million cubic feet equivalent per day (“Mmcfed”), and Eugene Island 113-B, in which REX has a 3.3% NRI, was temporarily shut-in.

 

During the past twelve months, REX has been awarded the following leases:

 

Contango Offshore Exploration LLC (COE)

 

Effective April 1, 2008, the Company sold a portion of its ownership interest in COE to an existing member or COE for approximately $0.9 million. As a result of the sale, the Company’s equity ownership interest in COE has decreased to 65.6%.

 

Grand Isle 72 (“Liberty”), a COE prospect operated by COI, began producing in March 2007 and as of August 22, 2008 was producing at a rate of approximately 0.2 Mmcfed. COE has invested approximately $5.5 million ($3.6 million net to the Company) in drilling, completion, pipeline and production facility costs as of June 30, 2008. COE has a 50% WI and a 40% NRI in this well. As of June 30, 2008, COE had borrowed $4.3 million from the Company under a promissory note (the “Note”) to fund a portion of its share of development costs at Grand Isle 72. The Note bears interest at a per annum rate of 10% and is payable upon demand. As of June 30, 2008, accrued interest thereon was $668,816.

 

Grand Isle 70, another COE prospect, was drilled by COI in July 2006 and proved to be a discovery. The well has been temporarily abandoned while alternative development scenarios are being evaluated. COE has a 45.1% WI before completion of the well and a 52.6% WI after completion of the well, while COI has a 3.6% WI before and after completion of the well. As of June 30, 2008, COE and COI had invested approximately $3.6 million to drill Grand Isle 70.

 

Ship Shoal 358, a COE prospect, is operated by a third party. The Company depends on third-party operators for the operation and maintenance of non-operated production platforms. As of August 12, 2008, Ship Shoal 358, in which COE has a 10.0% WI and 7.7% NRI, was producing at an 8/8ths rate of approximately 2.1 Mmcfed.

 

COI, a wholly-owned subsidiary of the Company, was formed for the purpose of drilling exploration and development wells in the Gulf of Mexico. COI operates and acquires significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, usually under a farm-out agreement, or similar agreement, with either REX or COE. COI expects to take working interests in these prospects under the same arms-length terms offered to industry third-party participants. In exchange for acting as operator, COI will receive a 10% ground floor working interest in all future wells. COI will pay the remaining 90% working interest and carry the owner of the lease (either REX or COE) for a 10% working interest through the tanks until initial production is achieved. Following a casing point election, the lease owner (either REX or COE) shall have an option to acquire a 25% working interest from COI. COI may also operate and acquire significant working interests in offshore exploration and development opportunities under farm-in agreements with third parties.

 

COI has recently drilled a well (“Eloise #1) on State of Louisiana leases at a depth below our Mary Rose discovery. The Company, through REX and COI participation, subject to elections for certain carried interests, has an approximate 54.17% WI in this well and is responsible for approximately $12.5 million of drilling costs. COI has agreed to provide REX with a carried interest in this well through the tanks. At casing point, REX “backed-in” for an additional working interest from COI and COI’s WI was reduced to approximately 36.90%. The Company expects to invest an additional $3.8 million to complete the well.

 

Effective February 1, 2008, the Company sold COI’s overriding royalty interest in Eugene Island 113-B, Ship Shoal 358 and Grand Isle 72 to JEX for $164,400.

 

CRC is a wholly-owned subsidiary of Contango formed for the sole purpose of drilling and operating exploration and development wells in our Dutch and Mary Rose leases in the Gulf of Mexico. Unlike COI, CRC will not acquire additional working interests in offshore exploration and development opportunities in the Gulf of Mexico.

 

Current Activities.

 

The Company’s financial advisor, Merrill Lynch & Co., has begun meeting with parties interested in potentially purchasing the Company’s Dutch and Mary Rose discoveries in the Gulf of Mexico. Any possible sale or restructuring is subject to mutually acceptable terms and conditions, mutually satisfactory documentation,

the consent and approval of third parties and governmental authorities, the approval of Contango’s board of directors and, if necessary, Contango’s shareholders. If Contango obtains an acceptable proposal to acquire its Dutch and Mary Rose discoveries, the disposition would likely be structured through the sale of Contango by its shareholders, with the potential purchaser acquiring the stock of Contango Oil & Gas Company and CRC. The Company’s remaining assets would be simultaneously spun-off to our shareholders through our subsidiary, Contango Energy Company. This structure would allow Contango shareholders to maintain an interest in any future exploration efforts at our other Gulf of Mexico leases.

 

A data room for the possible sale opened in July 2008. The Company anticipates receiving proposals in September 2008. If no acceptable proposals are received, the Company will terminate the sale and restructuring process and continue to develop and operate the Dutch and Mary Rose discoveries.

 

As of August 20, 2008, our three Dutch wells were flowing at a combined 8/8ths production rate of approximately 108.8 Mmcfed (approximately 41.5 Mmcfed net to Contango). The Company has invested approximately $33.8 million to drill and complete these three Dutch wells, including pipeline and production facility costs. The three Dutch wells flow to a third-party owned and operated production platform at Eugene Island 24. This platform has a capacity of 100 million cubic feet per day (“Mmcfd”) and 3,000 barrels of oil per day (“bopd”).

 

As of August 22, 2008, our four Mary Rose wells were flowing at a combined 8/8ths production rate of approximately 193.8 Mmcfed (approximately 71.4 Mmcfed net to Contango). The Company has invested approximately $69.1 million to drill and complete these four Mary Rose wells, including pipeline and production facility costs. The four Mary Rose wells flow into the Company’s recently completed production platform at Eugene Island 11, and through its associated pipeline into the ANR Pipeline Company facilities at Eugene Island 63. The gas is then processed on-shore near Patterson, Louisiana. The platform has been designed with a capacity of 500 Mmcfd and 6,000 bopd and the pipeline has been designed with a capacity of 330 Mmcfd and 6,000 bopd.

 

On April 3, 2008, the Company acquired additional working interests in the Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) discoveries in a like-kind exchange, using funds from the sale of its Eastern core Arkansas Fayetteville Shale properties held by a qualified intermediary. The Company purchased an additional 4.17% working interest and 3.33% net revenue interest in Dutch and an additional average 4.56% working interest and 3.33% net revenue interest in Mary Rose from three different companies for $100 million. The effective date of the transaction was January 1, 2008. On February 8, 2008, the Company purchased an additional 0.3% overriding royalty interest in the Dutch and Mary Rose discoveries for $9.0 million in a like-kind exchange, using funds from the sale of its Eastern core Arkansas Fayetteville Shale properties held by a qualified intermediary.

 

On January 3, 2008, the Company acquired an additional 8.33% working interest and 6.67% net revenue interest in Dutch and an additional average 9.11% working interest and 6.67% net revenue interest in Mary Rose from three different companies for $200 million, in a like-kind exchange, using funds from the sale of its Western core Arkansas Fayetteville Shale properties held by a qualified intermediary. The effective date of the transaction was January 1, 2008. As of August 22, 2008, the Company had a 47.05% working interest and 38.12% net revenue interest in Dutch, and an average 53.21% working interest and 37.00% net revenue interest in Mary Rose.

 

The Company’s independent third party engineer estimates the Dutch and Mary Rose discoveries to have total proved 8/8ths reserves as at June 30, 2008 of approximately 948 billion cubic feet equivalent (“Bcfe”) (366 Bcfe net to Contango). The Company has budgeted approximately $7.1 million to drill its first rate acceleration well (“Dutch #4”) in this field beginning September 2008, and may drill additional rate acceleration wells to fully exploit its Dutch and Mary Rose discoveries.

 

The Minerals Management Service (“MMS”) has implemented a rule on royalty relief for shallow water, deep shelf natural gas production from certain Gulf of Mexico leases. “Deep shelf gas” refers to natural gas produced from depths greater than 15,000 feet in waters of 200 meters or less. Royalty relief is available on the first 15 billion cubic feet (“Bcf”) of natural gas production if produced from an interval between 15,000 to less than 18,000 feet. Royalty relief is available on the first 25 Bcf of natural gas production if produced from an interval between 18,000 to less than 20,000 feet. Royalty relief is available on the first 35 Bcf of natural gas production if produced from well depths at or greater than 20,000 feet. This royalty relief is expected to have a positive impact on the economics of

deep gas wells drilled on the shelf of the Gulf of Mexico. The Company fully utilized its available MMS deep gas royalty relief in December 2007.

 

Producing Properties.  The following table sets forth the interests owned by Contango through CRC and its REX and COE affiliates in the Gulf of Mexico which are producing natural gas or oil as of August 22, 2008:

 

 

Leases.  The following table sets forth the working interests and status of the leases owned by Contango through CRC and COI, and its REX and COE affiliates in the Gulf of Mexico as of August 22, 2008:

 

 

 

 

In March 2008, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, sold its direct and indirect investments in Gridpoint, Inc., Trulite, Inc., Protonex Technology Corporation, Jadoo Power Systems, Contango Capital Partners Fund, L.P. and Contango Capital Partnership Management, LLC for $3.4 million, in the aggregate, recognizing a loss of approximately $2.9 million for the fiscal year ended June 30, 2008. CVCC’s only remaining alternative energy investment is Moblize, Inc. (“Moblize”).

 

The Company originally invested $1.2 million in Moblize in exchange for 648,648 shares of Moblize convertible preferred stock. In March 2008, the Company determined that Moblize was partially impaired, and wrote down the investment to $0.6 million, recognizing a loss of $0.6 million for fiscal year ended June 30, 2008. In June 2008, CVCC sold 205,000 shares of convertible preferred stock of Moblize to a third party for $410,000. As of August 22, 2008, CVCC owned 443,648 shares of Moblize convertible preferred stock, valued at $0.2 million, which represents an approximate 19.5% ownership interest. Moblize develops real time diagnostics and field optimization solutions for the oil and gas and other industries using open-standards based technologies.

 

Freeport LNG Development, L.P.

 

On February 5, 2008, the Company sold its ten percent (10%) limited partnership interest in Freeport LNG Development L.P. (“Freeport LNG”) to Turbo LNG LLC, an affiliate of Osaka Gas Co., Ltd., for $68.0 million, and recognized a gain of approximately $63.4 million on the sale. Freeport LNG is a limited partnership formed to develop, construct and operate a 1.75 billion cubic feet per day (“Bcfd”) liquefied natural gas (“LNG”) receiving and gasification terminal on Quintana Island, near Freeport, Texas.

 

The Company used $20.3 million of the proceeds from the sale to pay off its debt with The Royal Bank of Scotland plc, including principal, interest and fees. Another $20.0 million was used to pay off its debt with a private investment firm. The remaining $27.7 million was used for working capital purposes.

 

Arkansas Fayetteville Shale

 

On December 21, 2007, the Company sold its Western core Arkansas Fayetteville Shale properties to Petrohawk Energy Corporation for $199.2 million. The sale was effective October 1, 2007. The Company sold approximately 14,200 acres with 6.4 Mmcfd of production, net to Contango. The Company recognized a gain of approximately $155.9 million for the fiscal year ended June 30, 2008 as a result of this sale.

 

On January 30, 2008, the Company sold its Eastern core Arkansas Fayetteville Shale properties to XTO Energy, Inc. for approximately $128.0 million. The sale was effective December 1, 2007. The Eastern core consisted of approximately 11,200 acres with 3.0 Mmcfd of production, net to Contango. The Company recognized a gain of approximately $106.4 million for the fiscal year ended June 30, 2008 as a result of this sale.

 

Texas and Louisana

 

Effective February 1, 2008, the Company sold its interest in two on-shore wells to Alta Resources LLC. The Alta-Ellis #1 in Texas and the Temple-Inland in Louisiana were sold for approximately $1.1 million.

 

The Company currently derives its revenue principally from the sale of natural gas and oil. As a result, the Company’s revenues are determined, to a large degree, by prevailing natural gas and oil prices. The Company currently sells its natural gas and oil on the open market at prevailing market prices. Market prices are dictated by supply and demand, and the Company cannot predict or control the price it receives for its natural gas and oil. The Company has outsourced the marketing of its offshore natural gas and oil production volume to a privately-held third party marketing firm. The Company has a policy not to hedge its natural gas and oil production.

 

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

 

 

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

 

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

 

Environmental Matters.  Domestic natural gas and oil operations are subject to extensive federal regulation and, with respect to federal leases, to interruption or termination by governmental authorities on account of environmental and other considerations such as the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) also known as the “Super Fund Law”. The trend towards stricter standards in environmental legislation and regulation could increase costs to the Company and others in the industry. Natural gas and oil lessees are subject to liability for the costs of clean-up of pollution resulting from a lessee’s operations, and may also be subject to liability for pollution damages. The Company maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident of pollution may also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area.

 

The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent the Company’s offshore lease operations affect state waters, the Company may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether these financial responsibility requirements under the OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely affect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico.

 

The Company’s onshore operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws and regulations, among other things, impose absolute liability on the lessee for the cost of clean-up of pollution resulting from a lessee’s operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a significant impact on the operating costs of the Company, as well as the natural gas and oil industry in general. Federal, state and local initiatives to further regulate the disposal of natural gas and oil wastes are also pending in certain jurisdictions, and these initiatives could have a similar impact on the Company. The Company’s operations are also subject to additional federal, state and local laws and regulations relating to protection of human health, natural resources, and the environment pursuant to which the Company may incur compliance costs or other liabilities.

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

 

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

 

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

 

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

 

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

 

 

Kenneth R. Peak.  Mr. Peak is the founder and has been Chairman, Chief Executive Officer and Chief Financial Officer of Contango since its formation in September 1999. Mr. Peak entered the energy industry in 1972 as a commercial banker and held a variety of financial and executive positions in the oil and gas industry prior to starting Contango in 1999. Mr. Peak served as an officer in the U.S. Navy from 1968 to 1971. Mr. Peak received a BS in physics from Ohio University in 1967, and an MBA from Columbia University in 1972. He currently serves as a director of Patterson-UTI Energy, Inc., a provider of onshore contract drilling services to exploration and production companies in North America.

 

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

 

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

 

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

 

B.A. Berilgen.  Mr. Berilgen was appointed a director of Contango in July 2007. Mr. Berilgen has served in a variety of senior positions during his 38 year career. Currently, he is Chief Executive Officer of Patara Oil & Gas LLC. Prior to that he was Chairman, Chief Executive Officer and President of Rosetta Resources Inc., a company he founded in 2005. Mr. Berilgen was also previously the Executive Vice President of Calpine Corp. and President of Calpine Natural Gas L.P. from October 1999 through June 2005. In June 1997, Mr. Berilgen joined Sheridan Energy, a public

oil and gas company, as its President and Chief Executive Officer. Mr. Berilgen attended the University of Oklahoma, receiving a B.S. in Petroleum Engineering in 1970 and a M.S. in Industrial Engineering/Management Science.

 

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

 

Charles M. Reimer.  Mr. Reimer was elected a director of Contango in 2005. Mr. Reimer is President of Freeport LNG Development, L.P, and has experience in exploration, production, liquefied natural gas (“LNG”) and business development ventures, both domestically and abroad. From 1986 until 1998, Mr. Reimer served as the senior executive responsible for the VICO joint venture that operated in Indonesia, and provided LNG technical support to P. T. Badak. Additionally, during these years he served, along with Pertamina executives, on the board of directors of the P.T. Badak LNG plant in Bontang, Indonesia. Mr. Reimer began his career with Exxon Company USA in 1967 and held various professional and management positions in Texas and Louisiana. Mr. Reimer was named President of Phoenix Resources Company in 1985 and relocated to Cairo, Egypt, to begin eight years of international assignments in both Egypt and Indonesia. Prior to joining Freeport LNG Development, L.P. in December 2002, Mr. Reimer was President and Chief Executive Officer of Cheniere Energy, Inc.

 

Steven L. Schoonover.  Mr. Schoonover was elected a director of Contango in 2005. Mr. Schoonover was most recently Chief Executive Officer of Cellxion, L.L.C., a company specializing in construction and installation of telecommunication buildings and towers, as well as the installation of high-tech telecommunication equipment. From 1990 until its sale in November 1997 to Telephone Data Systems, Inc., Mr. Schoonover served as President of Blue Ridge Cellular, Inc., a full-service cellular telephone company he co-founded. From 1983 to 1996, he served in various positions, including President and Chief Executive Officer, with Fibrebond Corporation, a construction firm involved in cellular telecommunications buildings, site development and tower construction. Mr. Schoonover has been awarded, on two occasions with two different companies, Entrepreneur of the Year, sponsored by Ernst & Young, Inc Magazine and USA Today.

 

Darrell W. Williams.  Mr. Williams has been a director of Contango since 1999. From 2005 through 2007, Mr. Williams was President and Chief Executive Officer of Porta-Kamp International LP, which specializes in the manufacture, supply and construction of remote area housing, and Chief Executive Officer of Clearwater Environmental Systems, a manufacturer of sewage and water treatment systems. From 2002 until 2005, Mr. Williams was Managing Director of Catalina Capital Advisors, LP. Prior to joining Catalina, Mr. Williams was in senior executive positions with Deutug Drilling, GmbH (1993-2002), Nabors Drilling (1988-1993), Pool Company (1985-1988), Baker Oil Tools (1980-1983), SEDCO (1970-1980), Tenneco (1966-1970), and Humble Oil (1964-1966). Mr. Williams graduated from West Virginia University with a degree in Petroleum Engineering in 1964. Mr. Williams is past Chairman of the Houston Chapter of International Association of Drilling Contractors, a life member of the Society of Petroleum Engineers and a registered professional engineer in Texas.

 

Directors of Contango serve as members of the board of directors until the next annual stockholders meeting, until successors are elected and qualified or until their earlier resignation or removal. Officers of Contango are elected by the board of directors and hold office until their successors are chosen and qualified, until their death or until they resign or have been removed from office. All corporate officers serve at the discretion of the board of directors. Each outside director of the Company receives a quarterly retainer of $8,000 payable in cash and $36,000 payable annually in Company common stock. Each outside director also receives a $1,000 cash payment for each board meeting and separately scheduled Audit Committee meeting attended. The Chairman of the Audit Committee receives an additional quarterly cash payment of $3,000. There are no family relationships between any of our directors or executive officers.

 

We lease our corporate offices at 3700 Buffalo Speedway, Suite 960, Houston, Texas 77098. On September 30, 2006 we extended the term of our lease agreement for an additional 60 months, commencing November 1, 2006, with a termination date of October 31, 2011.

 

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.

 

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.

 

 

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

 

We have no ability to control the prices that we receive for natural gas and oil. Natural gas and oil prices fluctuate widely, and a substantial or extended decline in natural gas and oil prices would adversely affect our revenues, profitability and growth and could have a material adverse effect on the business, the results of operations and financial condition of the Company.

 

Our revenues, profitability and future growth depend significantly on natural gas and crude oil prices. Prices received affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and our ability to raise additional capital. We do not expect to hedge our production to protect against price decreases. Lower prices may also affect the amount of natural gas and oil that we can economically produce. Factors that can cause price fluctuations include:

 

 

A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our access to capital and the quantities of natural gas and oil that may be economically produced by us. A significant decrease in price levels for an extended period would negatively affect us.

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

 

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

 

We are highly dependent on the technical services provided by JEX and could be seriously harmed if JEX terminated its services with us or became otherwise unavailable.

 

Because we have only six employees, none of whom are geoscientists or petroleum engineers, we are dependent upon JEX for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. We do not have a written agreement with JEX which contractually obligates them to provide us with their services in the future. Highly qualified explorationists and engineers are difficult to attract and retain. As a result, the loss of the services of JEX could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, the loss by JEX of certain explorationists could have a material adverse effect on our operations as well.

 

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

 

Our business plan, which includes participation in 3-D seismic shoots, lease acquisitions, the drilling of exploration prospects and producing property acquisitions, has required and is expected to continue to require substantial capital expenditures. We may require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, additional financing may not be available to us on acceptable terms, if at all. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.

 

It is difficult to quantify the amount of financing we may need to fund our planned growth. The amount of funding we may need in the future depends on various factors such as:

 

 

We frequently obtain capital through the sale of our producing properties.

 

The Company, since its inception in September 1999, has raised approximately $484.0 million from various property sales. These sales bring forward future revenues and cash flows, but our longer term liquidity could be impaired to the extent our exploration efforts are not successful in generating new discoveries, production, revenues and cash flows. Additionally, our longer term liquidity could be impaired due to the decrease in our inventory of producing properties that could be sold in future periods. Further, as a result of these property sales the Company’s ability to collateralize bank borrowings is reduced which increases our dependence on more expensive mezzanine debt and potential equity sales. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.

 

We assume additional risk as Operator in drilling high pressure wells in the Gulf of Mexico.

 

COI and CRC are wholly-owned subsidiaries of the Company, formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. COI is currently the operator of Eloise #1 and Grand Isle 72, and CRC is currently the operator for our Dutch and Mary Rose discoveries.

Drilling activities are subject to numerous risks, including the significant risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. Drilling costs could be significantly higher if we encounter difficulty in drilling offshore exploration wells. The Company’s drilling operations may be curtailed, delayed, canceled or negatively impacted as a result of numerous factors, including inexperience as an operator, title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and fabrication yards. In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for drilling rigs, drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the offshore oil and gas industry in particular. This may lead to difficulty and delays in consistently obtaining certain services and equipment from vendors, obtaining drilling rigs and other equipment at favorable rates and scheduling equipment fabrication at factories and fabrication yards. This, in turn, may lead to projects being delayed or experiencing increased costs. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or we may not recover all or any of our investment. The risk of significant cost overruns, curtailments, delays, inability to reach our target reservoir and other factors detrimental to drilling and completion operations may be higher due to our inexperience as an operator.

 

Additionally, we use turnkey contracts that cost more, and under certain conditions, the turnkey contract can be terminated by the turnkey drilling contractor, leading to higher risks and costs for the Company.

 

We rely on third-party operators to operate and maintain some of our production pipelines and processing facilities and as a result we have limited control over the operations of such facilities and the interests of an operator may even differ from our interests.

 

We depend upon the services of third-party operators to operate production platforms, pipelines, gas processing facilities and the infrastructure required to produce and market our natural gas, condensate and oil. We have limited influence over the conduct of operations by third-party operators. As a result, we have little control over how frequently and how long our production is shut-in when production problems, weather and other production shut-ins occur. Poor performance on the part of, or errors or accidents attributable to, the operator of a project in which we participate may have an adverse effect on our results of operations and financial condition. Also, the interest of an operator may differ from our interests.

 

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

 

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

 

Concentrating our capital investment in the Gulf of Mexico increases our exposure to risk.

 

Our capital investments are focused in offshore Gulf of Mexico prospects. However, our exploration prospects in the Gulf of Mexico may not lead to significant revenues. Furthermore, we may not be able to drill productive wells at profitable finding and development costs.

 

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

 

Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows would be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Further, the majority of our reserves are proved developed producing. Accordingly, we do not have significant opportunities to

increase our production from our existing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.

 

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

 

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

 

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

 

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in this report. In addition, estimates of our proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control and may prove to be incorrect over time. As a result, our estimates may require substantial upward or downward revisions if subsequent drilling, testing and production reveal different results. Furthermore, some of the producing wells included in our reserve report have produced for a relatively short period of time. Because some of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a more lengthy production history. Any downward adjustment could indicate lower future production and thus adversely affect our financial condition, future prospects and market value.

 

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

 

The Company’s revenue activities are significantly concentrated in one field.

 

The proved reserves assigned to our Dutch and Mary Rose discoveries have seven producing well bores concentrated in one reservoir. As of August 29, 2008, this reservoir had only nineteen months of production history, and was producing via two pipelines and two production platforms. Reserve assessments based on only seven well bores in one reservoir with relatively limited production history are subject to greater risk of downward revision than multiple well bores from several mature producing reservoirs.

 

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

 

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

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

 

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

 

 

Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our drilling activities would materially and adversely affect our future cash flows and results of operations.

 

In addition, as a “successful efforts” company, we choose to account for unsuccessful exploration efforts (the drilling of “dry holes”) and seismic costs as a current expense of operations, which immediately impacts our earnings. Significant expensed exploration charges in any period would materially adversely affect our earnings for that period and cause our earnings to be volatile from period to period.

 

The natural gas and oil business involves many operating risks that can cause substantial losses.

 

The natural gas and oil business involves a variety of operating risks, including:

 

 

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

 

 

 

Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizing and collisions. In addition, offshore operations, and in some instances, operations along the Gulf Coast, are subject to damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce the funds available for exploration, development or leasehold acquisitions, or result in loss of properties.

 

If we were to experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, any one of which could adversely affect our ability to conduct operations. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, and particular types of coverage may not be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

 

Not hedging our production may result in losses.

 

Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if our production should be shut-in during a period when NYMEX natural gas prices increase, our policy is to hedge only through the purchase of puts. By not hedging our production, we may be more adversely affected by declines in natural gas and oil prices than our competitors who engage in hedging arrangements.

 

Our ability to market our natural gas and oil may be impaired by capacity constraints and equipment malfunctions on the platforms, gathering systems, pipelines and gas plants that transport and process our natural gas and oil.

 

All of our natural gas and oil is transported through gathering systems, pipelines, processing plants, and offshore platforms. Transportation capacity on gathering system pipelines and platforms is occasionally limited and at times unavailable due to repairs or improvements being made to these facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation agreements. If the gathering systems, processing plants, platforms or our transportation capacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition and results of operations. Further, repeated shut-ins of our wells could result in damage to our well bores that would impair our ability to produce from these wells and could result in additional wells being required to produce our reserves.

 

We may not have title to our leased interests and if any lease is later rendered invalid, we may not be able to proceed with our exploration and development of the lease site.

 

Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to not incur the expense of retaining title lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of JEX and others to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. However, such deficiencies may not have been cured by the

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

 

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

 

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

 

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

 

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

 

 

Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain only limited insurance coverage for sudden and accidental environmental damages. Accordingly, we may be subject to liability, or we may be required to cease production from properties in the event of environmental damages. These laws and regulations have been changed frequently in the past. In general, these changes have imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated factual developments could cause us to make environmental expenditures that are significantly different from those we currently expect. Existing laws and regulations could be changed and any such changes could have an adverse effect on our business and results of operations.

 

We cannot control the activities on properties we do not operate.

 

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

 

 

We are highly dependent on our management team, JEX, exploration partners and third-party consultants and any failure to retain the services of such parties could adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies.

 

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

 

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

 

We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers favorable. The successful acquisition of natural gas and oil properties requires an assessment of:

 

 

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:

 

 

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:

 

 

 

Our common stock is thinly traded.

 

Contango has approximately 16.8 million shares of common stock outstanding, held by approximately 92 holders of record. Directors and officers own or have voting control over approximately 3.4 million shares. Since our common stock is thinly traded, the purchase or sale of relatively small common stock positions may result in disproportionately large increases or decreases in the price of our common stock.

 

 

None.

 

 

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

 

 

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:

 

 

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.

 

 

The productive and non-productive onshore wells listed above relate strictly to our investment in the Arkansas Fayetteville Shale. At the time the Company sold its interest in the Arkansas Fayetteville Shale wells, the Company had 16 wells that were being drilled. We have classified those 16 wells as non-productive.

 

Our principal natural gas and oil properties consist of natural gas and oil leases. The following table indicates our interests in developed and undeveloped acreage as of June 30, 2008:

 

 

 

 

 

Included in the Offshore Gulf of Mexico acres shown in the table above are the beneficial interests Contango has in the offshore acreage owned by its partially-owned subsidiaries. The above table includes (i) our 32.3% interest in Republic Exploration LLC’s 1,163 net developed acres and 121,685 net undeveloped acres, and (ii) our 65.6% interest in Contango Offshore Exploration LLC’s 3,000 net developed acres and 75,476 net undeveloped acres. In addition, the Company holds royalty interests in approximately 10,760 gross undeveloped acres (484 net undeveloped acres) and 5,000 gross developed acres (71 net developed acres), offshore in the Gulf of Mexico.

 

The following table sets forth the number of gross and net productive natural gas and oil wells in which we owned an interest as of June 30, 2008:

 

 

 

 

The following table presents our estimated net proved natural gas and oil reserves and the pre-tax net present value of our reserves at June 30, 2008, based on a reserve report generated by William M. Cobb & Associates, Inc. The pre-tax net present value, discounted at 10%, is not intended to represent the current market value of the estimated natural gas and oil reserves we own.

 

The pre-tax net present value of future cash flows attributable to our proved reserves prepared in accordance with SEC guidelines as of June 30, 2008 was based on $13.095 per million British thermal units (“MMbtu”) for natural gas at the NYMEX and $140.00 per barrel of oil at the West Texas Intermediate Posting, in each case before adjusting for basis, transportation costs and British thermal unit (“Btu”) content. For further information concerning the present value of future net cash flows from these proved reserves, see “Supplemental Oil and Gas Disclosures”.

 

 

The process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our

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

 

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

 

 

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

 

 

During the quarter ended June 30, 2008, no matters were submitted to a vote of security holders.

 

 

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.

 

 

On August 22, 2008, the closing price of our common stock on the American Stock Exchange was $77.98 per share, and there were approximately 16.8 million shares of Contango common stock outstanding, held by approximately 92 holders of record.

 

We have not declared or paid any dividends on our shares of common stock. Any future decision to pay dividends on our common stock will be at the discretion of our board and will depend upon our financial condition, results of operations, capital requirements, and other factors our board may deem relevant.

 

On May 17, 2007, we sold $30.0 million of our Series E preferred stock to a group of private investors. The sale of the Series E preferred stock was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder, as a transaction not involving a public offering. The Series E preferred stock was convertible at any time by the holder into shares of our common stock at a price of $38.00 per share. The

dividend on the Series E preferred stock was paid quarterly in cash at a rate of 6.0% per annum. We used the net proceeds to repay $15.0 million in debt outstanding from the Company’s $30.0 million term loan agreement and to fund the Company’s offshore Gulf of Mexico deep shelf exploration program.

 

During the quarter ended March 31, 2008, four Series E preferred stockholders voluntarily elected to convert a total of 2,400 shares of Series E preferred stock to 315,786 shares of our common stock. The converted shares of Series E preferred stock had a face value of $12.0 million. During the quarter ended June 30, 2008, the final three Series E preferred stockholders voluntarily elected to convert a total of 3,600 shares of Series E preferred stock to 473,682 shares of our common stock. The converted shares of Series E preferred stock had a face value of $18.0 million.

 

The following table sets forth information about our equity compensation plan at June 30, 2008:

 

 

On February 13, 2008, the Company’s board of directors approved the purchase of an aggregate of 99,333 stock options from three officers of the Company and one member of its board of directors for approximately $5.9 million, in the aggregate. The board also approved the purchase of 10,000 shares of common stock from one member of its board of directors for approximately $0.7 million. All purchases were completed during the three months ended March 31, 2008. The Company does not have a program to repurchase shares of our common stock.

The following graph compares the yearly percentage change from June 30, 2003 until June 30, 2008 in the cumulative total stockholder return on our common stock to the cumulative total return on the Russell 2000 Stock Index and a peer group of five independent oil and gas exploration companies selected by us. The companies in our selected peer group are Brigham Exploration Company, Carrizo Oil & Gas, Inc., Edge Petroleum Corp., Goodrich Petroleum Corp. and PetroQuest Energy, Inc. Our common stock began trading on the American Stock Exchange on January 19, 2001 and previously traded on the Nasdaq over-the-counter Bulletin Board. The graph assumes that a $100 investment was made in our common stock and each index on June 30, 2003 and that all dividends were reinvested. The stock performance for our common stock is not necessarily indicative of future performance.

 

Comparison of Fiscal Year 2008 Cumulative Total Return