During the fiscal year ended June 30, 2009, the Company’swe successfully worked over our Mary Rose #1 well was successfully worked over at a cost of approximately $11.5 million ($6.1$6.1 million, net to Contango),Contango, and our Mary Rose # 2 well at a cost of approximately $3.0 million, net to Contango, to reduce water production from a water bearing sand above our production reservoir.production. We also installed line heaters at a cost of approximately $0.9 million, net to Contango, at the Eugene Island 11 platform which allowed us to further increase our production rate. Production had been constrained due to entrained water that attached to the paraffin in our condensate. The line heaters were installed at a cost of approximately $1.9 million ($0.9 million net to Contango).

Index to Financial Statements

The Company’s Mary Rose #2 well was successfully worked over in May 2009 at a cost of approximately $5.6 million ($3.0 million net to Contango), to also reduce water production from a water bearing sand above our production reservoir.

In September 2008, COI purchased additional working interests in nine offshore lease blocks from existing owners for a total of $2.1 million. See “Offshore Properties” below for a detailed description of the interests owned in our offshore properties.

During the fiscal year ended June 30, 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 Arkansas Fayetteville Shale properties held by a qualified intermediary. The Company purchased an additional 12.5 % working interest and 10.0% net revenue interest in Dutch and an additional average 13.67% working interest and 10.0% net revenue interest in Mary Rose from three different companies for $300 million. The Company also purchased an additional 0.3% overriding royalty interest in the Dutch and Mary Rose discoveries for $9.0 million.

Republic Exploration LLC (REX)

West Delta 36, a REX prospect, is operated by a third party. The Company depends on a third-party operator for the operation and maintenance of this production platform. As of August 31, 2010, the well was temporarily shut-in. As of August 25, 2010 however,18, 2011, the well was producing at an 8/8ths rate of approximately 2.9 million cubic feet equivalent per day (“Mmcfed”).5.5 Mmcfed. REX has a 25.0% working interest (“WI”), and a 20.0% net revenue interest (“NRI”), in this well.

During the fiscal year ended June 30, 2009, COI spuddrilled Eugene Island 56 #1 (“High Country West”) and West Delta 77 (“Devil’s Elbow”), both REX prospects, which were both determined to be dry holes. COI had a 100% WI and paid 100% of the drilling costs for both wells, totaling approximately $16.5 million. These costswhich together with associated leasehold costs and prospect fees oftotaled approximately $2.3 million are reflected as exploration expenses in the Company’s Consolidated Statements of Operations for the fiscal year ended June 30, 2009.

During the fiscal year ended June 30, 2009, the Company sold a portion of its ownership interest in REX to an existing member of REX for approximately $0.8 million. This sale decreased the Company’s equity ownership interest in REX to its present 32.3%. REX was formed for the purpose of generating exploration opportunities in the Gulf of Mexico. REX focuses 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. See Exhibit 21.2 for an organizational chart of our subsidiaries.

During the fiscal year ended June 30, 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 owed by REX to a private investment firm under a $50.0 million demand promissory note with such private investment firm (the “REX Demand Note”). 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$19.6 million.

Contango Offshore Exploration LLC (COE)

Contango Offshore Exploration (“COE”) was dissolved on June 1, 2010. Prior to its dissolution, on June 1, 2010,COE was 65.6% owned by Contango, and JEX would generate natural gas and oil prospects through COE. Immediately prior to its dissolution, COE owed the Company owned a 65.6% equity$5.9 million in principal and interest in COE. As of June 1, 2010, COE had borrowed $4.3 million from the Company under a non-recourse promissory note (the “Note”“COE Note”) payable on demand. As of June 1, 2010, accrued and unpaid interest on the Note was approximately $1.6 million. In connection with the dissolution, the Company assumed its 65.6% share of the obligation under the COE Note, while the other member of COE assumed the remaining 34.4%, or approximately $2 million. This $2 million is reflected as a receivable in the Consolidated Balance Sheet ofwas paid back to the Company as ofduring the fiscal year ended June 30, 2010.2011.

Index to Financial Statements

PriorExploration Alliance with JEX

JEX is a private company formed for the purpose of assembling domestic natural gas and oil prospects, either individually, or through our 32.3% owned affiliated company, REX. We do not have a written agreement with JEX which contractually obligates them to its dissolution, COE had generated three prospects which were all drilled by COI: Ship Shoal 263, Grand Isle 70provide us with their services. Once we have purchased a prospect, however, from either JEX or REX, we have historically entered into a participation agreement and Grand Isle 72. In connection with its dissolution, COE distributed its ownership interest in Ship Shoal 263 to its members. As a result, Contango has ajoint operating agreement specifying each participant’s working interest, of approximately 92.46% and a net revenue interest, and description of approximately 74% in this well. As of August 31, 2010 we had invested approximately $38.2 million to drill, complete and bring Ship Shoal 263 to full production status.

Grand Isle 70 (“Red Queen”) was drilled in July 2006 and was temporarily abandoned while alternative development scenarios were being evaluated. Effective December 1, 2009 the Company and COE sold their respectivewhen such interests in Grand Isle 70 to an independent third-party oil and gas company in exchange forare earned, as well as allocating an overriding royalty interest. The Company subsequently soldinterest of up to 3.33% to benefit employees of JEX.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango, through its overriding royalty interests to JEX for a gainwholly-owned subsidiary COI and its partially-owned affiliate, REX, conducts exploration activities in the Gulf of $112,868.

Grand Isle 72 (“Liberty”) ceased producing in October 2009 and the well was plugged and abandoned in June 2010. The Company invested approximately $500,000 to permanently abandon the site. This lease was relinquished to the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) (previously the Minerals Management Service) duringMexico. During the fourth quarter of our fiscal year ending June 30, 2010.

In June 2010, the Company withdrew from Ship Shoal 358, a COE prospect, and transferred all future plugging and abandonment liabilities to the third party operator responsible for operation and maintenance of the production platform.

Impact of Hurricanes Gustav and Ike

During the fiscal year ended June 2009, Hurricanes Gustav30, 2011, the Company relinquished 12 lease blocks to the BOEMRE, and Ike movedallowed two additional lease blocks to expire in accordance with their terms. As of August 24, 2011, Contango, through the Gulf of MexicoCOI and it was necessary for us to shut-in our Dutch and Mary Rose production at various times before, during and after the storms. OurREX, had an interest in 15 offshore facilities sustained minor damage from Hurricane Ike. Repairs were completed on the damaged wells at an 8/8ths cost of approximately $2.4 million, which was covered by the Company’s insurance subject to a deductible. The on-shore third-party processing and pipeline facilities on which we rely, however, incurred significant damage from Hurricane Ike and necessitated approximately three months of downtime for our production while repairs were being made.leases.

Offshore Properties

Producing Properties.The following table sets forth the interests owned by Contango through its related entities in the Gulf of Mexico which were producing natural gas or oil as of August 31, 2010:24, 2011:

Index to Financial Statements

Leases.The following table sets forth the interests owned by Contango through its related entities in leases in the Gulf of Mexico as of August 31, 2010:24, 2011:

Index to Financial Statements

Onshore Exploration and Properties

Conterra CompanySouth Texas.

Effective OctoberIn May 2011, the Company spud its on-shore wildcat exploration well (Rexer-Tusa #2) in south Texas. On May 13, 2011, the Company sold 75% of its working interest in Rexer-Tusa #2 and the purchaser became the operator. As a result of this sale, the Company now has a 25% working interest (18.4% net revenue interest) before payout, and an 18.8% working interest (13.8% net revenue interest) after payout. The estimated costs to drill, complete and bring this well to production are approximately $1.1 million, net to Contango. See “Property Sales and Discontinued Operations” below for additional information.

Alta Energy Partners LLC

On April 12, 2011, the Company announced a commitment to invest up to $20 million over the next two years in Alta Energy Partners LLC (“Alta Energy”), a venture that will acquire, explore, develop and operate onshore unconventional shale operated and non-operated oil and natural gas assets. Other participants include Alta Resources, LLC and Blackstone Capital Partners. As of August 24, 2011, we had invested approximately $0.4 million in Alta Energy.

Property Sales and Discontinued Operations

On May 13, 2011 the Company sold substantially all of its onshore Texas assets to Patara Oil & Gas LLC (“Patara”) for an aggregate purchase price of $40 million ($38.7 million after adjustments). The properties were sold effective April 1, 2009,2011 and consist of the Company’s wholly-owned subsidiary, ConterraJoint Venture and South Texas assets.

Joint Venture Assets

The Company (“Conterra”), entered into a joint venture with Patara Oil & Gas LLC (“Patara”), a privately held oil and gas company,in October 2009 to develop proved undeveloped Cotton Valley gas reserves in Panola County, Texas. B.A. Berilgen, a member of the Company’s board of directors, is the Chief Executive Officer of Patara.

Under The Company sold its 90% interest and 5% overriding royalty interest in the terms21 wells drilled under this joint venture. The Company sold the assets for approximately $36.2 million and recognized a pre-tax loss of approximately $0.7 million. These 21 wells had proved reserves of approximately 16.7 Bcfe, net to Contango. The Company has accounted for this sale as discontinued operations as of June 30, 2011 and has included the results of the joint venture agreement (the “Joint Venture Agreement”), Conterra will fundoperations in discontinued operations for all periods presented.

South Texas

The Company sold 100% of its interest in Rexer #1 and 75% of its interest in Rexer-Tusa #2 for approximately $2.5 million and recognized a pre-tax loss of approximately $0.3 million. Rexer #1 is a wildcat exploration well that was spud in June 2010 and began producing in October 2010. This well had proved reserves of approximately 0.5 Bcfe, net to Contango. Rexer-Tusa #2 is another wildcat exploration well that was spud in May 2011. This well had no proved reserves at the drilling and completion costs in exchange for 90%time of sale.

Contango Mining Company

Contango Mining Company (“Contango Mining”), a wholly-owned subsidiary of the net revenues. The Joint Venture Agreement contemplates drilling upCompany and the predecessor to Contango ORE, Inc. (“CORE”), was initially formed on October 15, wells, at2009 as a Delaware corporation registered to do business in Alaska for the purpose of engaging in exploration in the State of Alaska for (i) gold and associated minerals and (ii) rare earth elements. Contango Mining held leasehold interests in approximately 647,000 acres from the Tetlin Village Council, the council formed by the governing body for the Native Village of Tetlin, an estimated 8/8ths costAlaska Native Tribe (“Tetlin Lease”) and held 12,000 acres in unpatented mining claims from the State of approximately $1.65 million per well. The average 8/8ths reserves per well are approximately 1.5 Bcfe (1.125 net Bcfe after a 25% royalty)Alaska for the exploration of gold deposits and associated minerals (together with the Tetlin Lease, the “Gold Properties”). In July 2010, both ConterraContango Mining also held interests in 3,520 acres of unpatented Federal mining claims and Patara agreed to enter into a second joint venture agreement to drill up to an additional 15 wells, bringing97,280 acres of unpatented mining claims from the total expected numberState of wells to 30.Alaska for the exploration of rare earth elements (the “REE Properties”, and together with the Gold Properties, the “Properties”).

Index to Financial Statements

By paying allOn November 29, 2010, CORE, then another wholly-owned subsidiary of the drillingCompany, acquired the assets and completion costs,assumed the obligations of Contango Mining, including the Properties, in exchange for its common stock which was subsequently distributed to the Company’s stockholders of record as of October 15, 2010 on the basis of one share of common stock for each ten shares of the Company’s common stock then outstanding. No fractional shares were issued, but a cash payment was made to shareholders with less than ten shares based upon the value established for CORE. The Company will be ablealso contributed $3.5 million in cash to benefitCORE immediately prior to the distribution.

The Company has obtained a valuation report from Avalon Development Corporation, a Fairbanks, Alaska-based mineral exploration consulting firm, of the associated tax deductions which arevalue of the assets constituting the Properties acquired by CORE. Based on that valuation report and the $3.5 million cash contributed to CORE, the aggregate value of the assets contributed to CORE and distributed to Company shareholders was estimated to be about 75%approximately $0.46 per share of total drilling costs, or approximately $1.2 million per well. Upon the Company achieving a 15% per annum cash-on-cash rateContango Oil & Gas Company. The shares of returnCORE trade on the basket of 15 wells,OTCBB under the Company’s net revenue interest converts into a 5% overriding royalty interest.

As of August 31, 2010, we were producing at a rate of approximately 5.6 Mmcfed, net to Contango, from 12 wells. Three additional wells have been logged and are waiting to be fracture stimulated while another one well is drilling ahead. As of August 31, 2010 we have invested approximately $25.8 million in this drilling program.

South Texas

In July 2010, the Company announced a discovery at its on-shore wildcat exploration well (Rexer #1) in south Texas.symbol CTGO. The Company no longer has a 100% working interest (72.5% net revenue interest)an ownership in this well before payout,CORE and a 75% working interest (54.4% net revenue interest) after payout. Production is expected to begin by the end of October 2010. As of June 30, 2010, the Company had invested approximately $4.2 million to drill, complete and prepare to bring this well to production.

Contango Mining Company

During the fiscal year ended June 30, 2010, the Company created a new wholly-owned subsidiary, Contango Mining Company (“Contango Mining”), to initially invest up to $3.0 million to conduct mineral exploration activities on approximately 647,000 acres of Alaska Native and State of Alaska lands located in interior Alaska (“Mineral Exploration Lands”). Contango Mining purchased a 50% ownership from a private company for $1.0 million, together with our commitment to invest the next $2.0 million of capital expenditures to fund the expenses associated with the initial mineral exploration phase on this acreage. Contango Mining andhas included its partner will share expenses on a 50/50 basis thereafter and each will own a 50% working interest burdened by varying amounts of a production royalty and a 1% overriding royalty interest. To date, Contango Mining has invested a total of $2.6 million.

Contango Mining has also assembled with the private company approximately 100,000 acres of State of Alaska and Federal unpatented mining claims for the purpose of conducting exploration work for rare earth minerals. Our decision to acquire the mining claims is based, in part, on the results of several surveys performed by the United States Geological Surveyoperations and gain on disposition in the 1970’s and 1980’s.

The Company anticipates reorganizing Contango Mining in order to pursue additional exploration activities in the state of Alaska.discontinued operations for all periods presented.

Contango Venture Capital Corporation

During the fiscal year ended June 30, 2008, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, sold its direct and indirect investments in several alternative energy investments for approximately $3.4 million, recognizing a loss of approximately $2.9 million. CVCC’s only remaining investment is Moblize, Inc. (“Moblize”). As of August 31, 2010, CVCC owned 443,648 shares of Moblize convertible preferred stock, 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.

Property Sales and Discontinued Operations

Freeport LNG Development, L.P.

During the fiscal year ended June 30, 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

Index to Financial Statements

Osaka Gas Co., Ltd., for $68.0 million, and recognized a pre-tax gain of approximately $63.4 million on the sale. Freeport LNG is a limited partnership formed to develop, construct and operate a 1.75 billion cubic feet per day (“Bcfd”) liquefied natural gas (“LNG”) receiving and gasification terminal on Quintana Island, near Freeport, Texas.

Arkansas Fayetteville Shale

During the fiscal year ended June 30, 2008, the Company sold its Arkansas Fayetteville Shale properties to Petrohawk Energy Corporation and XTO Energy, Inc. for a total of approximately $327.2 million. The Company sold approximately 25,400 acres with 9.4 Mmcfd of production, net to Contango. The Company recognized a gain of approximately $262.3 million as a result of this sale.

Texas and Louisiana

During the fiscal year ended June 30, 2008, the Company sold its interest in two onshore wells to Alta Resources LLC. The Alta-Ellis#1 in Texas and the Temple-Inland in Louisiana were sold for approximately $1.1 million.

Marketing and Pricing

The Company currently derives its revenue principally from the sale of natural gas and oil. As a result, the Company’s revenues are determined, to a large degree, by prevailing natural gas and oil prices. The Company currently sells its natural gas and oil on the open market at prevailing market prices. Major purchasers of our natural gas, oil and natural gas liquids for the fiscal year ended June 30, 20102011 were ConocoPhillips Company (37%), Shell Trading US Company (24%(26%), AtmosNJR Energy Marketing, LLC (16%Services (25%) and, ConocoPhillips Company (23%), Enterprise Products Operating LLC (13%(9%), and TransLouisiana Gas Pipeline Inc. (7%). 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:

Competition

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

Governmental Regulations

Federal Income Tax.Federal income tax laws significantly affect the Company’s operations. The principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to

Index to Financial Statements

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 and to claim a manufacturing deduction 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).qualified production activities.

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 any 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 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.

Impact of Deepwater Horizon Incident.In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon, engaged in drilling operations for another operator, sank after an apparent blowout and fire. The accident resulted in the loss of life and a significant oil spill. In response to the Incident, the President of the United States has announced a six-month moratorium on drilling in the deepwater Gulf of Mexico and imposed new restrictions on permitting activities onincident, the Outer Continental Shelf. AlthoughShelf Safety Oversight Board, established by the root cause, or causes,Secretary of the Deepwater Horizon IncidentInterior, issued its recommendations for the strengthening of permitting, inspections, enforcement and environmental stewardship. In addition, the BOEMRE developed an implementation plan for the recommendations, many of which are unclear at this time, we believe there is a high likelihood of regulatory and/already underway or legislative changes that will impact operations in the Gulf of Mexico. Various Congressional committees have already begun pursuing legislation to change existing governmental regulations. We will continue to monitor the expected regulatory and legislative response and its impact on our operations.planned.

Index to Financial Statements

On September 30, 2010, the Department of the Interior announced two new rules (The Drilling Safety Rule and the Workplace Safety Rule) that are intended to improve drilling safety by strengthening requirements for safety equipment, well control systems, and blowout prevention practices on offshore oil and gas operations, and improve workplace safety.

The Deepwater Horizon incident is likely to have a significant and lasting effect on the US offshore energy industry, and will likely result in a number of fundamental changes, including heightened regulatory scrutiny, more stringent operating and safety standards, changes in equipment requirements and the availability and cost of insurance, as well as increased politicization of the industry. These changes may result in increases in our operating and development costs and extend project development timelines because of new regulatory requirements. There may be other impacts of which we are not aware at this time.

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 BOEMRE administers the natural gas and oil leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The BOEMRE 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 BOEMRE 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 BOEMRE requires companies operating on the Outer Continental Shelf to obtain surety bonds to ensure performance of these obligations. As an operator, 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 for the Company than it would be for other similarly situated natural gas producers and sellers.

Risk and Insurance Program

In accordance with industry practices,practice, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us an economically appropriate level of financial protection from significant unfavorable losses resulting from damages to, or the loss of, physical assets or loss of human life, and liability claims of third parties.parties, including such occurrences as well blowouts and weather events that result in oil spills

Index to Financial Statements

and damage to our wells and/or platforms. Our goal is to balance the cost of insurance with our assessment of the potential risk of an adverse event. We maintain insurance at levels that we believe are appropriate and consistent with industry practice.practice and we regularly review our risks of loss and the cost and availability of insurance and revise our insurance program accordingly.

WeWhile the Company renewed its energy package and insurance policies in January 2011 at rates similar to the prior year, we expect the future availability and cost of insurance to be impacted by the recent Deepwater Horizon incident.Incident. Impacts could include: tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico, including possible increases in liability caps for claims of damages from oil spills. We will continue to monitor the expected regulatory and legislative response and its impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection at a level that we can afford considering the cost of insurance, against the potential and magnitude of disruption to our operations and cash flows.

Recently, various Congressional committeesWe carry insurance protection for our net share of any potential financial losses occurring as a result of events such as the Deepwater Horizon Incident. As a result of the incident, we have begun pursuing legislationincreased our well control coverage from $75 million to increase or remove$100 million on certain wells, which covers control of well, pollution cleanup and consequential damages. We have increased our general liability caps forcoverage from $100 million to $150 million, which covers pollution cleanup, consequential damages coverage, and third party personal injury and death. And we have increased our Oil Spill Financial Responsibility coverage from $35 million to $150 million, which covers additional pollution cleanup and third party claims coverage.

Health, Safety and Environmental Program.The Company’s Health, Safety and Environmental (“HS&E”) Program is supervised by an operating committee of senior management to insure compliance with all state and federal regulations. In addition, to support the operating committee, we have contracted with J. Connors Consulting (“JCC”) to manage our regulatory process. JCC is a regulatory consulting firm specializing in the offshore Gulf of Mexico drilling.regulatory process, preparation of incident response plans, safety and environmental services and facilitation of comprehensive oil spill response training and drills to oil and gas companies and pipeline operators.

For our Gulf of Mexico operations, we have a Regional Oil Spill Plan in place with the BOEMRE. Our response team is trained annually and is tested through annual spill drills given by the BOEMRE. In addition, we have in place a contract with O’Brien’s Response Management (“O’Brien’s”). O’Brien’s maintains a 24/7 manned incident command center located in Slidell, LA. Upon the occurrence of an oil spill, the Company’s spill program is initiated by notifying O’Brien’s that we have an emergency. While the Company would focus on source control of the spill, O’Brien’s would handle all communication with state and federal agencies as well as U.S. Coast Guard notifications.

If a spill were to occur, we have contracted with Clean Gulf Associates (“CGA”) to assist with equipment and personnel needs. CGA specializes in onsite control and cleanup and is on 24 hour alert with equipment currently stored at six bases (Ingleside and Galveston, TX and Lake Charles, Houma, Venice and Pascagoula, LA), and is opening new sites in Leeville, Morgan City and Harvey, LA. The current $75 million liability limit under the Oil Pollution ActCGA equipment stockpile is likelyavailable to be materially increased or lifted in its entirety. Suchserve member oil spill response needs including blowouts; open seas, near shore and shallow water skimming; open seas and shoreline booming; communications; dispersants; boat spray systems to apply dispersants; wildlife rehabilitation; and a requirement could ultimately requireforward command center. CGA has retainers with an aerial dispersant company and a company to maintain either an insurance coverage minimum larger than Contango is able or willing to meet, or a financial size and equity position significantly larger than Contango is able to meet. The insurance market may be unable to provide coverage enhancements to address any significant increasesthat provides mechanical recovery equipment for spill responses. CGA equipment includes:

Index to Financial Statements

In addition to being a member of CGA, the Company has contracted with Wild Well Control for source control at the wellhead, if required. Wild Well Control is one of the world’s leading providers of firefighting, well control, engineering, and training services.

Safety and Environmental Management System. On September 30, 2010, the BOEMRE issued a final rule that requires operators to develop and implement a Safety and Environmental Management System (“SEMS”) to address oil and gas operations in the Outer Continental Shelf (“OCS”). The final rule became effective on November 15, 2010 and requires full implementation of the following thirteen mandatory elements of the American Petroleum Institute’s Recommended Practice 75 (API RP 75) on or before November 15, 2011:

Our SEMS program must identify, address, and manage safety, environmental hazards, and its impacts during the design, construction, start-up, operation, inspection, and maintenance of all new and existing facilities. The Company is responsible for establishing goals, performance measures, training, accountability for its implementation, and providing necessary resources for an effective SEMS, as well as reviewing the adequacy and effectiveness of the SEMS program. Facilities must be designed, constructed, maintained, monitored, and operated in a manner compatible with industry codes, consensus standards, and all applicable governmental regulations. We have contracted with Island Technologies Inc. to manage our SEMS program for production operations.

The BOEMRE will enforce the SEMS requirements through audits. We must have our SEMS program audited by either an independent third-party or our designated and qualified personnel within 2 years of the initial implementation and at least once every 3 years thereafter. Failure to implement an effective SEMS program by November 15, 2011 or failure of an audit may force us to shut-in our Gulf of Mexico drilling entails significant inherent risks and increasingly, political risk as well. If an event occurs that is not covered by insurance or not fully protected by insured limits, it would likely have a material adverse impact on our financial condition, results of operations and cash flows.operations.

Employees

We have eight employees, all of whom are full time. Effective March 1, 2010, theThe Company outsourcedoutsources its human resources function to Insperity, Inc. (formerly Administaff Companies II, LP (“Administaff”)LP) and all of the Company’s employees becameare co-employees of Administaff.Insperity, Inc. In addition to our employees, 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

Index to Financial Statements

working interest owner, we rely on outside operators to drill, produce and market our natural gas and oil for our onshore prospects and certain offshore prospects where we are a non-operator. In the offshore prospects where we are the operator, we rely on a turn-key contractor to drill and rely on independent contractors to produce and market our natural gas and oil. In addition, we utilize the services of independent contractors to perform field and on-site drilling and production operation services and independent third party engineering firms to calculate our reserves.

Directors and Executive Officers

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

Kenneth R. Peak.Mr. Peak is the founder of the Company and has been Chairman and Chief Executive Officer since its formation in September 1999. Mr. Peak entered the energy industry in 1973 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.

Marc Duncan. Mr. Duncan joined Contango in June 2005 as President and Chief Operating Officer of Contango Operators, Inc. and was appointed President and Chief Operating Officer of Contango Oil & Gas Company in October 2006. Mr. Duncan has over 26 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 Chief Operating Officer of USENCO International, Inc. and its subsidiaries and affiliates in China and Ukraine from February 2000 to July 2004 and as a senior project and drilling engineer for Hunt Oil Company from July 2004 to June 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.

Index to Financial Statements

Sergio Castro.Mr. Castro joined Contango in March 2006 as Treasurer and was appointed Vice President, Treasurer and TreasurerSecretary in April 2006 and Chief Financial Officer in June 2010. Prior to joining Contango, Mr. Castro spent two years (April 2004 to March 2006) as a consultant for UHY Advisors TX, LP. From January 2001 to April 2004, Mr. Castro was a lead credit analyst for Dynegy Inc. From August 1997 to January 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 CPA and a Certified Fraud Examiner.

Yaroslava Makalskaya. Ms. Makalskaya joined Contango in March 2010 and was appointed Vice President, Controller and ControllerChief Accounting Officer in June 2010. Prior to joining Contango, Ms. Makalskaya was a director of the Transaction Services practice at PricewaterhouseCoopers, where she assisted clients with M&A transactions as well as advised clients with complex accounting and financial reporting issues. Ms.MakalskayaPrior to July 2008 Ms. Makalskaya was a Senior Manager in the audit practice of PricewaterhouseCoopers and Arthur Andersen, where her clients included many US and international companies in energy, utilities, mining and other sectors. Ms. Makalskaya holds a MS degree in economicsEconomics from Novosibirsk State University in Russia. Ms. Makalskaya is a CPA and has approximately 1819 years of work experience in accounting and finance, including 13 years in public accounting. During her work in the audit practice of PricewaterhouseCoopers and Arthur Andersen, her clients included many US and international companies in energy, utilities and mining and other sectors.

Charles A. Cambron. Mr. Cambron joined Contango in August 2010 as Vice President of Operations. Mr. Cambron has 19over 20 years of experience in the Gulf of Mexico oil and gas industry. Most recently he was employed by Applied Drilling Technology, Inc. (ADTI) as an Operations Manager from August 1995 until August 2010. He also held various positions in engineering and offshore supervision over a 15 year period. Prior

Index to Financial Statements

to ADTI, Mr. Cambron began his career with Rowan Petroleum, Inc. as a Drilling Engineer working in both the Gulf of Mexico and North Sea. Mr. Cambron received a B.S.BS degree in Petroleum Engineering from the University of Oklahoma in 1991.

Marc Duncan. Mr. Duncan joined Contango in June 2005 as President and Chief Operating Officer of Contango Operators, Inc. and was appointed President and Chief Operating Officer of Contango Oil & Gas Company in October 2006 until December 2010. In December 2010 Mr. Duncan was appointed as the Company’s Safety, Environmental and Regulatory Compliance Officer (“SEARCO”). Mr. Duncan has over 37 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 Chief Operating Officer of USENCO International, Inc. and its subsidiaries and affiliates in China and Ukraine from February 2000 to July 2004 and as a senior project and drilling engineer for Hunt Oil Company from July 2004 to June 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 3940 year career. Most recently, he became Chief Executive Officer of Patara Oil & Gas LLC in April 2008. Prior to that he was Chairman, Chief Executive Officer and President of Rosetta Resources Inc., a company he founded in June 2005, until his resignation in July 2007, and then he was an independent consultant from July 2007 through April 2008. 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 a co-founding partner of Southplace, LLC, a provider of private-company middle-market corporate finance advisory services. Mr. Brehmer founded Southplace, LLC in November 2002. In August 2004, Mr. Brehmer became Managing Director of Houston Capital Advisors LP, a boutique financial advisory, merger and acquisition investment bank, while still retaining his membership in Southplace, LLC. Mr. Brehmer resigned from Houston Capital Advisors LP in January 2008 and is currently associated with Southplace, LLC in a full-time capacity. 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 November 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

Index to Financial Statements

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 November 2005. Mr. Schoonover was most recently Chief Executive Officer of Cellxion, L.L.C., a company he founded in September 1996 and sold in September 2007, which specialized in construction and installation of

Index to Financial Statements

telecommunication buildings and towers, as well as the installation of high-tech telecommunication equipment. Since the sale in September 2007, Mr. Schoonover continues to serve as a consultant to the current management team of Cellxion, L.L.C. 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.

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. InDuring fiscal year 2011 and 2010, each outside director of the Company received a quarterly retainer of $20,000 payable in cash, with no stock option or common stock grants. There were no additional payments for meetings attended or being chairman of a committee. There are no family relationships between any of our directors or executive officers.

InDuring fiscal year 2009, and 2008, each outside director of the Company received a quarterly retainer of $8,000 payable in cash and $36,000 payable annually in Company common stock. Each outside director also received a $1,000 cash payment for each board meeting and separately scheduled Audit Committee meeting attended. The Chairman of the Audit Committee received an additional quarterly cash payment of $3,000.

Corporate Offices

We lease our corporate offices at 3700 Buffalo Speedway, Suite 960, Houston, Texas 77098. Our existing 60 monthIn November 2010, the Company expanded its office space and extended its office lease agreement expires on Octoberthrough December 31, 2011.2015.

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 atwww.contango.com. www.contango.com.

Available Information

General information about us can be found on our Websitewebsite atwww.contango.com. 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 Websitewebsite as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission (“SEC”).

Item 1A.Risk Factors

Index to Financial Statements

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.

Index to Financial Statements

We have no ability to control the prices that we receivemarket price 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 and Chief Executive 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 chairmanChairman and chief executive officer.Chief Executive 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 employ no 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 JEX to provide us with its 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. We have historically entered into agreements with JEX and its affiliates when we purchase prospects from JEX and its affiliates that specify the terms and conditions of purchase.

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

Index to Financial Statements

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

Index to Financial Statements

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$524 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 and high temperature wells in the Gulf of Mexico.

COI, a wholly-owned subsidiary of the Company, was formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. 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 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 may cost more than drilling contracts at daily rates. Under certainShould our contracts come off turnkey due to events such as adverse weather conditions, difficulties encountered while drilling, or the termination of such turnkey contract can be terminated by the turnkey drilling contractor which(under certain conditions), our drilling costs could lead to materially higher risks and costs for the Company.be significantly higher.

Index to Financial Statements

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. The interests of an operator may 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 well bores are required to be shut-in from time to time due to a variety of issues, including a combination of weather, mechanical problems, sand production, bottom sediment, water and paraffin associated with our condensate production at our Eugene Island 11 platform, as well as downstream third-party facility and pipeline shut-ins. In addition, shut-ins are necessary from time to time to upgrade and improve 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.

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, which may result in a total loss of our investment. Furthermore, even our productive wells may not result in profitable operations.

Gulf of Mexico exploration efforts have been on-going for over 60 years and remaining prospects are at deeper, more expensive horizons and often in much deeper water depths. As a result, a number of companies have decided to shift their focus to onshore “shale plays.” The Company’s continuing focus on the Gulf of Mexico may not lead towill result in significant revenues. Furthermore, we may not be able to drill productive wells at profitable findingdry hole costs, perhaps in excess of $30 million for one well, which significantly concentrates and development costs.increases our risk profile.

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 will 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 of our reserves.

There are numerous uncertainties in estimating crude oil and natural gas reserves and their value, including many factors that are beyond our control. It requires interpretations of available technical data and

Index to Financial Statements

various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities 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.

Index to Financial Statements

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 a reserve 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. Accordingly, some of our reserve estimates are not based on a multi-year production decline curve and are calculated using a reservoir simulation model together with volumetric analysis. Any downward adjustment could indicate lower future production and thus adversely affect our financial condition, future prospects and market value.

In June 2010, the Company revised its offshore reserves downward by approximately 48.5 Bcfe. This revision was attributable to newly learned bottom hole pressure data as a result of a recent field wide shut-in and a “P/Z pressure test” that indicated fewer reserves than originally estimated.

The Company’s reserves and revenues are primarily concentrated in one field.

TheApproximately 83% of our proved reserves are assigned to our Dutch, and Mary Rose and Eloise discoveries which have ten producing well bores concentrated in two reservoirs on one field, and are producing via two pipelines andthrough two production platforms. Reserve assessments based on only ten well bores in two reservoirs with relatively limited production history are subject to significantly greater risk of downward revision than multiple well bores frombeing shut-in for a variety of mature producing reservoirs.weather, platform and pipeline difficulties. In addition, the risk of a downward revision in our reserve estimates is also greater.

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:

Index to Financial Statements

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.

Index to Financial Statements

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.

Production activities in the Gulf of Mexico increase our susceptibility to pollution and natural resource damage.

A blowout, rupture or spill of any magnitude would present serious operational and financial challenges. Most of the Company’s operations are on the Gulf of Mexico shelf in water depths less than 200 feet and less than 50 miles from the coast. Such proximity to the shore-line increases the probability of a biological impact or damaging the fragile eco-system in the event of released condensate.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions in the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and several countries including countries in the European Union have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatory programs.

The Environmental Protection Agency (the “EPA”) has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA issued a final rule requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has proposed such greenhouse gas regulations and may issue final rules at a subsequent date.

Several decisions have been issued by courts that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases

Index to Financial Statements

may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the natural gas and condensate that we produce.

The natural gas and oil business involves many operating risks that can cause substantial losses.losses and our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.

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.

Index to Financial Statements

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. Many 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, many 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.

Index to Financial Statements

The proposed United States federal budget for 2011 and other pending legislation contain certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

In February 2009, the current federal administration released its budget proposals for 2010, which included numerous proposed tax changes. In April 2009, legislation was introduced to further these objectives and in February 2010, the federal administration released similar budget proposals for 2011. The proposed budget and legislation would repeal many tax incentives and deductions that are currently used by oil and gas companies in the United States and impose new taxes. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands. Should some or all of these provisions become law, taxes on the E&P industry would increase, which could have a negative impact on our results of operations and cash flows. Although these proposals initially were made in 2009, none have become law. It is still, however, the federal administration’s stated intention to enact legislation to repeal tax incentives and deductions and impose new taxes on oil and gas companies.

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:

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 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.

Our operations in the Gulf of Mexico could behave been adversely affected by changes in laws and regulations which have occurred and are expected to continue to occur as a result of the Deepwater Horizon Incident.

In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon was engaged in drilling operations for another operator and sank after an apparent blowout and fire. The accident resulted in the loss of life and a significant oil spill. On May 27, 2010, in response to the incident, the President of the United States announcedAs a six-month moratorium on drilling in the deepwater Gulf of Mexico and imposed new restrictions on permitting activities on the Outer Continental Shelf. On July 12, 2010, the Secretary of the Interior revised the moratorium that is scheduled to end November 30, 2010. In conjunction with the moratorium,result, the Department of the Interior issued a directive calling for additional safety and performance standards as well as rigorous monitoring and testing requirements. More recently,In addition, various Congressional committees have begunbegan pursuing legislation to regulate drilling activities, establish safety requirements and increase liability for oil spills.

Index to Financial Statements

We are monitoringcontinue to monitor legislative and regulatory developments; however,developments, including the Drilling Safety Rule and the Workforce Safety Rule issued by the Department of the Interior. However, the full legislative and regulatory response to the incident is not yetfully known. An expansion of safety and performance regulations or an increase in liability for drilling activities maywill have one or more of the following impacts on our business:

Any of the above factors may result in a reduction of our cash flows, profitability, and the fair value of our properties.

New regulatory requirements and permitting procedures recently imposed by the BOEMRE have significantly delayed our ability to obtain permits to drill new wells in offshore waters.

Subsequent to the Deepwater Horizon incident in the Gulf of Mexico, the BOEMRE issued a series of Notices to Lessees (“NTLs”) imposing new regulatory requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. These new regulatory requirements include the following:

Since the adoption of these new regulatory requirements, BOEMRE has been taking much longer to review and approve permits for new wells. Due to the extremely slow pace of permit review and approval, the BOEMRE may now take four months or longer to approve applications for drilling permits that were previously approved in less than 30 days. The new rules also increase the cost of preparing each permit application and will increase the cost of each new well.

The BOEMRE has implemented much more stringent controls and reporting requirements that if not followed, could result in significant monetary penalties or a shut-in of all or a portion of our Gulf of Mexico operations.

The BOEMRE is the federal agency responsible for overseeing the safe and environmentally responsible development of energy and mineral resources on the OCS. They are responsible for leading the most aggressive and comprehensive reforms to offshore oil and gas regulation and oversight in U.S. history. Their reforms strengthen requirements for everything from well design and workplace safety to corporate accountability.

Index to Financial Statements

One of the many reforms includes implementing a SEMS program. This program requires operators to identify, address, and manage safety, environmental hazards, and its impacts during the design, construction, start-up, operation, inspection, and maintenance of all new and existing facilities. Facilities must be designed, constructed, maintained, monitored, and operated in a manner compatible with industry codes, consensus standards, and all applicable governmental regulations. Failure to implement an effective and robust SEMS program by November 15, 2011 or failure to comply with the program may force us to cease operations in the Gulf of Mexico.

Additionally, the OCS Lands Act authorizes and requires the BOEMRE to provide for both an annual scheduled inspection and a periodic unscheduled (unannounced) inspection of all oil and gas operations on the OCS. In addition to examining all safety equipment designed to prevent blowouts, fires, spills, or other major accidents, the inspections focus on pollution, drilling operations, completions, workovers, production, and pipeline safety. Upon detecting a violation, the inspector issues an Incident of Noncompliance (“INC”) to the operator and uses one of two main enforcement actions (warning or shut- in), depending on the severity of the violation. If the violation is not severe or threatening, a warning INC is issued. The warning INC must be corrected within a reasonable amount of time specified on the INC. The shut-in INC may be for a single component (a portion of the facility) or the entire facility. The violation must be corrected before the operator is allowed to continue the activity in question.

In addition to the enforcement actions specified above, the BOEMRE can assess a civil penalty of up to $35,000 per violation per day if: 1) the operator fails to correct the violation in the reasonable amount of time specified on the INC; or 2) the violation resulted in a threat of serious harm or damage to human life or the environment. Operators with excessive INCs may be forced to cease operations in the Gulf of Mexico.

We do not 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

Index to Financial Statements

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, our 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.

Index to Financial Statements

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:

The risks and challenges inherent in mineral exploration are quite different from our natural gas and oil exploration and we have no mineral expertise.

Our investment in Contango Mining does not represent a change in our natural gas and oil exploration business model. We recognize that the risks and challenges inherent in mineral exploration are quite different from our natural gas and oil exploration business. Our 2009 and early 2010 exploration programs found relatively few samples of commercial grade minerals but we believe our results merit continued exploration.

Index to Financial Statements

At this early exploration stage our investment should be considered speculative and the probability of ultimately being successful in finding gold or other minerals in a volume sufficient to support a commercial mining operation are quite low. We have little or no experience in mining and mineral development and will be highly dependent upon the advice of consultants.

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.

The Company adopted a Stockholders Rights Plan in September 2008, which will terminate September 30, 2011, that is designed to ensure that all stockholders of the Company receive fair value for their shares of common stock in a proposed takeover of the Company and to guard against coercive takeover tactics to gain control of the Company. In addition, these provisions, among other things, authorize the board of directors to:

Our common stock is thinly traded.

Contango has approximately 15.7 million shares of common stock outstanding. Directors and officers own or have voting control over approximately 3.2 million shares. Since our common stock is not heavily 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

Index to Financial Statements

Production, Prices and Operating Expenses

The following table presents information from continuing operations regarding the production volumes, average sales prices received and average production costs associated with our sales of natural gas, oil and natural gas liquids (“NGLs”) from continuing operations 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. Reported lease operating expenses include property and severance taxes.

Not included in the table above is production information from our discontinued operations. For the fiscal year ended June 30, 2011, our discontinued operations produced approximately 1,418 Mmcf of natural gas, 10.3 MBbls of condensate, and 2.6 million gallons of natural gas liquids at an average price of $3.31 per Mcf, $86.40 per Bbl and $0.96 per gallon, respectively. For the fiscal year ended June 30, 2010, our discontinued operations produced approximately 305 Mmcf of natural gas, 1.2 MBbls of condensate, and 428 thousand gallons of natural gas liquids at an average price of $3.72 per Mcf, $75.90 per Bbl and $1.04 per gallon, respectively.

Index to Financial Statements

Development, Exploration and Acquisition 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: