Attached files

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EX-10.1 - EXHIBIT 10.1 - Whiting Canadian Holding Co ULC	a2199688zex-10_1.htm
EX-32.2 - EXHIBIT 32.2 - Whiting Canadian Holding Co ULC	a2199688zex-32_2.htm
EX-31.2 - EXHIBIT 31.2 - Whiting Canadian Holding Co ULC	a2199688zex-31_2.htm
EX-32.1 - EXHIBIT 32.1 - Whiting Canadian Holding Co ULC	a2199688zex-32_1.htm
EX-31.1 - EXHIBIT 31.1 - Whiting Canadian Holding Co ULC	a2199688zex-31_1.htm

        A summary of the stock options outstanding as of June 30, 2010 is as follows:

        At June 30, 2010, stock options outstanding were as follows:

        The aggregate intrinsic value of both outstanding and vested options as of June 30, 2010 was $3,367,613 based on the Company's June 30, 2010 closing common stock price of $3.19 per share. The total grant date fair value of the shares vested during the six months ended June 30, 2010 was $1,579,817. As of June 30, 2010, there was $4,272,042 of total unrecognized compensation cost related to unamortized options. That cost is expected to be recognized over a period of approximately three years.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4—Stock-based Compensation Plan (Continued)

        As of June 30, 2010, there were 15,000 unvested shares of restricted stock with a weighted-average grant date fair value of $3.69 per share. Total unrecognized compensation cost of $29,333 related to non-vested restricted stock is expected to be recognized over a twelve month period. The Company recognizes compensation cost over the requisite service period for the entire award. The fair value of restricted stock grants is based on the stock price on the grant date and the Company assumes no annual forfeiture rate.

Note 5—Commitments and Contingencies

        The Company leases office facilities in Denver, Colorado and Dickinson, North Dakota under operating lease agreements that expire on June 30, 2012 and December 31, 2010, respectively. Rent expense for the Company's Denver, Colorado office was $129,669 and $104,409 for the six month periods ended June 30, 2010 and 2009, respectively.

        The following table shows the remaining annual rentals per year for the life of the Denver office space lease:

        During the second quarter of 2008, the Company entered into contracts for the use of two new-build drilling rigs. The first rig was placed into operation in November 2008 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior to September 15, 2010.

The contract can be extended by mutual consent of Kodiak and the drilling contractor at its termination. The estimated termination fee for this first rig is $1.8 million as of June 30, 2010. The second rig was placed into operation in March 2010 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior to March 10, 2012. This contract can also be extended by mutual consent. The estimated termination fee for the second rig is $4.8 million as of June 30, 2010. The Company is currently utilizing both rigs for drilling in the Williston Basin and expects to continue utilization through their respective terms.

        During the second quarter of 2010, the Company entered into a contract for the use of an additional drilling rig. We originally anticipated placing this third rig into operation in the fourth quarter of 2010; however, we recently entered into an agreement with a third party operator, pursuant to which the operator will utilize the rig through the first six months of the underlying drilling rig contract. The rig contract entails a one-year drilling commitment or specific termination fees if the contract is terminated prior to delivery of the rig. The contract may also be extended by mutual consent. The estimated termination fee for this third rig is $3.8 million as of June 30, 2010. Having the rig become available later in 2011 provides the Company alternatives that defer the decisions as to the timing of adding a third rig.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5—Commitments and Contingencies (Continued)

        As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost.

Note 6—Credit Facility

        On May 24, 2010, the Company, through its wholly-owned subsidiary, Kodiak USA, entered into a $200 million, four-year, revolving, senior secured credit agreement with Wells Fargo Bank, N.A. (the "Lender"). The outstanding principal balance of the revolving loan, together with all unpaid fees and expenses relating thereto, shall be due and payable no later than May 24, 2014. As of June 30, 2010, the Company had borrowed $5.0 million under the credit agreement. Subsequent to June 30, 2010, the Company borrowed an additional $2.5 million under the credit agreement.

        Concurrent with the credit agreement, the Company entered into a guarantee pursuant to which the Company guarantees to the Lender all of the obligations of Kodiak USA under the credit agreement and pledges a security interest in 100% of its equity interests in Kodiak USA as collateral support for its obligations under the guaranty and the obligations of Kodiak USA under the credit agreement. Additionally, Kodiak USA granted a security interest in substantially all of its assets, including mortgages on at least 80% of its interests in oil and gas properties on a discounted basis. Availability under the credit agreement is subject at all times to the then applicable borrowing base, which is recalculated with scheduled redeterminations at December 31 and June 30 of each year. The Company can request two additional redeterminations per year, thereby allowing for the ability to adjust the borrowing base up to four times in a calendar year. The borrowing base was $20.0 million as of June 30, 2010.

        The credit agreement also makes available to the Company standby letters of credit in an amount equal to the lesser of the then applicable borrowing base and $5,000,000 and reduces availability for loans under the credit agreement on a dollar for dollar basis. The Company had no outstanding standby letters of credit under the credit agreement as of June 30, 2010.

        Interest on the revolving loans is payable at one of the following two variable rates: the Alternate Base Rate for ABR Loans or the Adjusted LIBO Rate for Eurodollar loans, as selected by the Company, plus an additional percentage that can vary on a daily basis and is based on the daily unused portion of the facility. This additional percentage is referred to as the "Applicable Margin" and varies depending on the type of loan. The grid below shows the Applicable Margin options depending on the applicable Borrowing Base Utilization Percentage.

Borrowing Base Utilization Grid

        The credit agreement contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (a) covenants to comply with a current ratio of consolidated current assets to consolidated current liabilities not less than 1.0:1.0 and a

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6—Credit Facility (Continued)

ratio of total debt to EBITDAX (as defined in the credit agreement) not greater than 3.75:1.0; (b) limitations on liens and incurrence of debt covenants; (c) limitations on dividends, distributions, redemptions and restricted payments covenants; (d) limitations on investments, loans and advances covenants; and (e) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. As of June 30, 2010, the Company was in compliance with all covenants under the credit agreement.

Note 7—Fair Value Measurements

        ASC Topic 820 establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company's assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

•

Level 1: Quoted prices are available in active markets for identical assets or liabilities;



•

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;



•

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

        The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

        The following table presents the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2010 by level within the fair value hierarchy:

        The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company's own credit rating. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7—Fair Value Measurements (Continued)

to meet its potential repayment obligations associated with the derivative transactions. At June 30, 2010, derivative instruments utilized by the Company consist of a "no cost" collar. The crude oil derivative markets are highly active. Although the Company's derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

        Other financial instruments not measured at fair value on a recurring basis include cash and cash equivalents, accounts receivable, note receivable, accounts payable, and accrued liabilities. The financial statement carrying amounts of these items approximate their fair values due to their short-term nature.

Note 8—Differences Between Canadian and United States Accounting Principles

        These financial statements have been prepared in accordance with GAAP, which differ in certain respects with those principles and practices that the Company would have followed had its financial statements been prepared in accordance with accounting principles and practices generally accepted in Canada ("Canadian GAAP"). Management does not believe its financial statements would vary materially had they been prepared in accordance with Canadian GAAP or that any recently issued, not yet effective, Canadian accounting standards if currently adopted would have a material effect on the accompanying financial statements.

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ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

        The information discussed in this Quarterly Report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could," and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

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future capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;



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unsuccessful drilling and completion activities and the possibility of resulting write-downs;



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a decline in oil or natural gas production or oil or natural gas prices and the impact of general economic conditions on the demand for oil and natural gas and the availability of capital;



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geographical concentration of our operations;



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ongoing U.S. and global economic uncertainty;



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constraints imposed on our business and operations by our credit facility and our ability to generate sufficient cash flows to repay our debt obligations;



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availability of borrowings under our credit facility;



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termination fees related to drilling rig contracts;



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increases in the cost of drilling, completion and gas gathering or other costs of production and operations;



•

financial losses and reduced earnings related to our commodity derivative agreements, and failure to produce enough oil to satisfy our commodity derivative agreements;



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historical incurrence of losses;



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adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;



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hazardous, risky drilling operations and adverse weather and environmental conditions;



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limited control over non-operated properties, and reliance on third party service providers over whom we have limited control;



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reliance on limited number of customers and creditworthy of our customers;



•

title defects to our properties and inability to retain our leases;

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incorrect estimates of our proved reserves, and the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;



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our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped operated and non-operated acreage positions;



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our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;



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increases in interest rates;



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our ability to retain key members of our senior management and key technical employees, and conflicts of interests with respect to our directors;



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marketing and transportation constraints in the Williston Basin;



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risks associated with prior business activities;



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effects of competition;



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federal and tribal regulations and laws;



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our level of indebtedness;



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risks in connection with potential acquisitions and the integration of significant acquisitions;



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price volatility of oil and natural gas prices;



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impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;



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effect of seasonal factors;



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lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oil field services;



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further sales or issuances of common stock; and



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our common stock's limited trading history.

        Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in our filings with the SEC and in Part II, Item 1A of this Quarterly Report. For additional information regarding risks and uncertainties, please read our filings with the SEC under the Exchange Act and the Securities Act, including our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this Quarterly Report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

Overview

        Kodiak is an independent energy company focused on the exploration, exploitation, acquisition and production of crude oil and natural gas in the United States. Our oil and natural gas reserves and operations are primarily concentrated in two Rocky Mountain basins, the Williston Basin of North Dakota and Montana and the Green River Basin of Wyoming and Colorado. Kodiak's corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development

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and exploratory drilling opportunities on high potential conventional and non-conventional oil and natural gas prospects that we have the opportunity to explore, drill and develop.

Liquidity and Capital Resources

        Our original 2010 capital expenditure budget of approximately $60 million was substantially allocated to drilling and completion activities and we are maintaining those capital expenditures. We have revised our original 2010 capital expenditure budget to a total of $75 million primarily due to the addition of leased acreage in strategic areas and the finalization of a pipeline infrastructure contract requiring capital to connect our wells.

        In summary, the increase in our capital budget was primarily due to the following factors:

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As we have continued to explore opportunities to expand our acreage position, we have identified acreage that meets our strategic objectives. In the first six months of 2010, we spent approximately $10.1 million to lease acreage in strategic areas, and we have increased our capital expenditure budget to include these acquisitions.



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We have allocated approximately $4 million in planned capital expenditures for costs associated with our pipeline infrastructure and water intake facility. Through these expenditures, Kodiak will be able to capture revenue generated from the sales of its associated natural gas and natural gas liquids that are currently flared. The pipeline agreement also includes water gathering and disposal which can further reduce lease operating expense while minimizing surface disturbance by eliminating the trucking of water. The new water intake facility will eliminate significant trucking traffic and costs, as well as reduce the need to draw water from underground aquifers.



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We have experienced an increase in completion costs as we continue to refine completion techniques; however, these wells, despite the increased completion costs, still deliver strong rates of return given the improved performance over the life of the well due to such refinement. We have projected our gross well cost for 2010 to range from $6.5 to $8.5 million, depending on lateral length, number of fracture stimulation stages, proppant volume and, more significantly, proppant type.

        This revised capital expenditure budget remains subject to modification, both as to amount and allocation, and is subject to variation due to such factors as our drilling results, availability and cost of oil field services and equipment and expected commodity prices, as well as available working capital.

        In total, we have the potential for participation in as many as five gross rigs by mid-year 2011. In the second quarter of 2010, we contracted for delivery of a drilling rig that we intend to operate in addition to our two current rigs. We have recently reached an agreement with a third party operator for their continued usage of this rig through the first six months of the contract. As a result, this rig should be available to us during the second quarter of 2011. The third contracted rig does not have a skid package, so it is more suitable to single well drilling pads, providing us flexibility in our rig inventory. In addition, our partner in an area of mutual interest covering a portion of our acreage has indicated they will be mobilizing one rig in the fourth quarter of 2010 followed by a second in early 2011. Our interest in the wells drilled by this partner would vary, but within the area of mutual interest we would have a 50% working interest ownership. The largest increase in the drilling activity would occur in 2011.

        We expect to fund our revised capital budget primarily from working capital, anticipated cash flow from operations and borrowings under our reserve-based revolving credit facility. As of June 30, 2010, our remaining capital budget of approximately $50.0 million is more than our working capital of approximately $12.7 million and the then undrawn balance on our revolving credit facility of $15 million. We expect to fund the remaining portion of our revised capital budget by our cash flow from operations generated in the second half of 2010 in combination with the potential increase of our

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borrowing base for our revolving credit facility. As compared to cash flow from operations in the first half of 2010, we anticipate that our operating cash flows will increase as additional wells are drilled and placed on production. For the second quarter of 2010, our average production was 1,051 BOE per day. As a result of our drilling and completion activities, we anticipate our average production to grow to over 2,500 BOE per day by the end of 2010, provided that we are able to complete the wells that we have scheduled for completion in 2010. As of July 31, 2010, we have 5 gross wells (2.7 net) awaiting completion and project an additional 6 wells (3.7 net) will be completed prior to year end. Concurrently, we expect that our borrowing base will increase with the addition of proved properties as a result of our drilling activities. However, we cannot give assurance that either our cash flow from operations or increases in our borrowing base will be sufficient to fund our anticipated capital expenditures.

        If our existing and potential sources of liquidity through increased operating cash flows or our credit facility are not sufficient to undertake our revised capital expenditures, we may alter our drilling program, pursue joint ventures with third parties, sell interests in one or more of our properties or sell common shares or debt securities. There can be no assurance that any such transactions can be completed or that such transactions will satisfy our capital requirements. If we are not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our expenditures or restructure our operations, and we would be unable to implement our exploration and drilling program.

        During the first six months of 2010, we incurred capital expenditures of approximately $26.7 million. The table below sets forth our capital expenditures for the six months ended June 30, 2010,

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and our revised budgeted capital expenditures for 2010 for our principal properties. Net capital expenditures include both cash expenditures and accrued expenditures and are net of proceeds from divestitures.

        During the first six months of 2010, we drilled or participated in 10 gross wells (3.9 net) and completed 5 gross wells (2.2 net). In total, we anticipate drilling or participating in 20 gross wells (9.3 net) and completing 17 gross wells (9.2 net) during 2010. All of these wells are in our Williston Basin operating area.

        The following table sets forth our capital resources and liquidity as of and for the three and six month periods ended June 30, 2010 and 2009:

        Kodiak ended the first half of 2010 with total working capital of approximately $12.7 million, which included cash and cash equivalents of approximately $4.4 million, as compared to working capital of approximately $28.3 million at year-end 2009, which included cash and cash equivalents of approximately $24.9 million. An important component of our working capital is our inventory, prepaid expenses and other current assets. As operator of most of our current activity in the Williston Basin, we must place orders and take delivery of tubular goods in advance of actual drilling in order to assure availability of the tubular goods. As wells are drilled, these tubular goods become part of our cost of wells, whereby our working interest share is already paid while the portion related to other working interest partners is recovered through our joint interest billings. As of June 30, 2010, we had prepaid $10.7 million towards the cost of tubular goods, compared to $7.3 million at December 31, 2009.

        Our working capital alone is not sufficient to fund our remaining revised 2010 capital expenditure budget of approximately $50 million. We anticipate that cash flow from operations, in addition to increased borrowing under our reserve-based revolving credit facility, will be used to fund such

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remaining budgeted capital expenditures. We expect our operating cash flows and borrowing base to continue to increase as additional wells are drilled and placed on production. However, the increases in both of these sources are subject to our ability to complete the wells that we have scheduled for completion in 2010. As of July 31, 2010, we have 5 gross wells (2.7 net) awaiting completion and project an additional 6 wells (3.7 net) to be completed prior to year end. If we can achieve production rates that we have seen from our existing wells, we anticipate a strong increase in our production base. Concurrently, we expect that our borrowing base will increase with the addition of proved properties as a result of our drilling activities. However, we cannot give assurance that either our cash flow from operations or increases in our borrowing base will be sufficient to fund our anticipated capital expenditures. If our existing and potential sources of liquidity through increased operating cash flows or our credit facility are not sufficient to undertake our revised capital expenditures, we may alter our drilling program, pursue joint ventures with third parties, sell interests in one or more of our properties or sell common shares or debt securities. There can be no assurance that any such transactions can be completed or that such transactions will satisfy our capital requirements. If we are not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our expenditures or restructure our operations, and we would be unable to implement our exploration and drilling program.

        Our results of operations and financial condition are significantly affected by the success of our exploration and land leasing activity, the resulting production and reserves, oil and natural gas commodity prices and the costs related to operating our properties. In the six months ended June 30, 2010, our oil and natural gas revenue increased by approximately 328% from $2.8 million for the six months ended June 30, 2009 to $11.8 million for the six months ended June 30, 2010. This increase is largely the result of the increase in our crude oil production in 2010 compared to 2009, together with improved prices realized for our oil and natural gas production. Total costs and expenses increased to $10.3 million for the six months ended June 30, 2010 from $5.0 million for same period of 2009. This increase is primarily due to our increased lease operating expense resulting from adding ten wells to production from June 30, 2009 to June 30, 2010, the related severance taxes paid on production from the wells added and the increase in depletion due to the same wells added to our production base.

        In May 2010, we (through our wholly-owned subsidiary) entered into a credit agreement with a large commercial bank. The credit facility has a $20 million borrowing base as of June 30, 2010, which is subject to semi-annual redetermination. We are obligated to make periodic interest or other debt service payments related to the funds we borrow under the credit facility and we are subject to various restrictive covenants. The amount of our borrowing base is dependent on a number of variables, including our proved reserves, and assumptions regarding the price at which oil and natural gas can be sold. We currently have $7.5 million outstanding under our credit facility.

Properties

Williston Basin

        Our primary geologic targets in the Williston Basin are the Bakken and Three Fork Formations. The Williston Basin also produces from many other formations including, but not limited to, the Mission Canyon, Nisku and Red River. We are currently operating a two-rig program in the Williston Basin and currently anticipate continued operation throughout 2010 with these rigs. As previously mentioned, these two rigs are under two-year contracts that expire in the fourth quarter of 2010 and the first quarter of 2012, respectively. In the second quarter of 2010, we contracted for a third drilling rig from the same drilling contractor as the aforementioned rig contracts. As opposed to the first two rigs, the third rig does not have a skid package, which will provide us the flexibility to utilize the rig on single well pads while utilizing the other two rigs to drill multiple wells from one drilling pad. Recently, we entered into an agreement with a third party operator, pursuant to which the operator will utilize the rig through the first six months of the underlying drilling rig contract. By having the rig become

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available for delivery in 2011, we are provided with alternatives that defer the decisions as to the timing of adding a third rig. In addition to our operated rigs, we have been informed by our joint venture partner on the Fort Berthold Indian Reservation that they will be mobilizing a drilling rig later this year on the lands they operate with the expectation to add a second rig during the first part of 2011. While we do not know the drilling program for these rigs, we anticipate having a working interest of up to 50% in several of the wells to be potentially drilled by these two rigs.

        In the six months ended June 30, 2010, the Company's capital expenditures in the Williston Basin totaled $26.3 million, including $16.2 million for drilling and completion activities and $10.1 for acreage leasing. For the entire year of 2010, our revised capital expenditure budget for the Williston Basin includes $61.3 million for drilling and completion and related infrastructure and $13.3 million for acreage leasing.

Bakken/Three Forks Development: Dunn County, N.D. (55,775 gross and 34,635 net acres)

        In late July 2010, the Company completed the Moccasin Creek (MC) #13-34-28-2H (Kodiak-operated 59% working interest (WI) / 48% net revenue interest (NRI)) well. The well was completed in 15 stages through a 6,200-foot horizontal wellbore. The well has been flow tested for three days and has not stabilized sufficiently to report a 24-hour initial production rate. Over the last 12 hours prior to the filing of this quarterly report, the well flow-tested at rates between 70 to 80 barrels of oil per hour and 900 to 1,200 thousand cubic feet of natural gas (Mcf) per day through a 24/64th inch choke with 2,850 psi flowing surface pressure. During the 12-hour period, the well had cumulative oil production of 871 barrels of oil and 541 Mcf. Presently, the well is flowing back approximately 60% frac fluid and 40% oil. Kodiak continues to flow test the well and will turn in to permanent production facilities when testing is completed.

        As of July 31, 2010, the Company has three wells in Dunn County awaiting completion. The MC # 13-34-28-1H is a 9,769-foot horizontal lateral directly offsetting the MC#13-34-28-2H well discussed above and is currently being completed. Also awaiting completion is the Two Shields Butte (TSB) #14-21-4H well, which is a 4,500-foot horizontal lateral, and the TSB 14-21-33-16H3 well, a 9,300 foot horizontal lateral drilled in the Three Forks Formation. These wells are the first two wells drilled from the TSB four-well pad.

        Kodiak is currently drilling ahead on the TSB # 14-21-33-15H, a projected 9,000-foot lateral and the TSB #14-21-16-2H, a projected 9,000 foot lateral, will follow. It is expected that these four wells on the shared pad will be completed during the fourth quarter of 2010.

        The Company has a 7.15% working interest in two wells drilled from one pad by another operator. One of the wells was drilled and has been completed in the Middle Bakken and had a reported curtailed initial production rate of 1,385 BOE/d. The second well was drilled in Three Forks Formation and is currently awaiting completion.

McKenzie County, N.D. (13,430 gross and 9,565 net acres)

        In the Grizzly project area, located in the Mondak Field of the southeastern Elm Coulee trend, the Grizzly #13-6-H-R (Kodiak operated—68% working interest / 56% net revenue interest) was re-entered during June 2010 and a 3,700-foot lateral was drilled horizontally in the Middle Bakken Formation and is currently undergoing completion operations.

        We are currently drilling the Grizzly Federal #1-27H-R well, a proposed 9,600-foot horizontal lateral test of the Middle Bakken Formation. The well is a twin to the Grizzly Federal #1-27 well, which was drilled and completed in 2007 using single-stage fracture stimulation procedures.

        After drilling is completed on the Grizzly Federal #1-27H-R well, we intend to relocate the drilling rig to our Koala acreage block. The first well expected to be drilled will be the Koala

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#9-5-6-5H well, followed by the Koala #9-5-6-5H3 well (both Kodiak operated—74.7% working interest / 61.3% net revenue interest).

        The following summary provides a tabular presentation of data pertinent to Kodiak's Middle Bakken and Three Forks drilling and completion activities during 2010 (gas is converted on a 6 Mcf to 1 barrel of oil basis):

Red River Formation: Sheridan County, Mont.

        The Harshbarger #13-20-29 (Kodiak operated—43% working interest / 34% net revenue interest) was recently completed and production testing is continuing at this time. We are currently utilizing workover rigs on our Bakken acreage and once that work is completed, we will mobilize back on this well and finish our completion work.

Midstream Activities: Oil, Gas and Water Disposal Pipelines and Water Intake Facilities

        In late June, Kodiak reached a definitive agreement with a third-party pipeline operator that allows for the gathering and sales of crude oil and natural gas and gathering and disposal of water through pipelines over certain of the Company's Dunn County gross acreage position. The Company's joint venture partner in this area that operates a portion of Kodiak's leasehold had previously reached an agreement with the same pipeline operator. Combined, these agreements allow all of the wells completed by either company within the area of mutual interest to produce into the same gathering and pipeline system.

        The gathering system will run through the northern part of Kodiak's Dunn County leasehold and connect four of the Company's currently producing wells. Furthermore, the pipeline will accommodate the Company's remaining 2010 drilling with one of the Company's drilling rigs, including the TSB four-well pad currently being drilled. Moving oil and gas quantities through the pipeline system eliminates trucking costs and associated surface disturbance and mitigates weather-related production interruptions. Additionally, Kodiak can capture revenue generated from the sales of its associated natural gas and natural gas liquids that are currently flared. The pipeline agreement also includes water gathering and disposal which can further reduce lease operating expense while minimizing surface disturbance by eliminating the trucking of water.

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        Kodiak also recently entered into an exclusive definitive agreement with the Three Affiliated Tribes and the state of North Dakota for the construction of a water intake facility that accesses water from the nearby Missouri River. The water will be used for operational needs, including fracture stimulations. The new water intake facility is expected to eliminate significant trucking traffic and costs, as well as reduce the need to draw water from underground aquifers. Kodiak expects to have the facility operational by the end of the fourth quarter of 2010, subject to federal regulatory approvals.

Green River Basin (47,867 gross and 15,056 net acres)

        We have been notified by the operator of the Vermillion Basin prospect that they intend to re-enter a well that was vertically drilled in 2008 to the top of the Baxter Shale and horizontally drill a lateral to evaluate the potential of the Baxter Shale interval. We have not allocated significant capital to this project, as we expect to be carried for these expenditures under our current contract with the operator.

Production, Average Sales Prices and Production Costs

        Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. Commodity prices are beyond our control and are difficult to predict. Market prices reflect worldwide concerns regarding economic conditions and demand for petroleum products, amid a host of uncertainties caused by political instability, fluctuations in the U.S. dollar and crude oil refining constraint. We receive lower prices for our oil and gas than what is posted on the New York Mercantile Exchange ("NYMEX"). The price differentials received for our products vary from month to month, and we have limited commodity price hedges in place.

        The Company's oil and gas sales volumes are directly related to the results of its exploratory and acquisition activities. Production volumes may vary monthly as various wells are completed or maintained in an effort to provide optimal production. Sales volumes, prices received and production costs are summarized in the following table for the three and six month periods ended June 30, 2010 and June 30, 2009.

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Results of Operations

For the Three Months Ended June 30, 2010 compared to the Three Months Ended June 30, 2009

        The Company reported net income for the three months ended June 30, 2010 of approximately $621,000 compared to a net loss of $538,000 for the same period in 2009. The improvement from a net loss to net income is attributable to the new production from our Bakken wells, which includes sales from one recently completed Bakken well which came on to production in the second quarter of 2010. Our volumes on a BOE basis increased 112% from 45,127 BOE in the second quarter of 2009 to 95,671 BOE during the second quarter of 2010. In addition, we realized increased prices for both oil and natural gas during the three month period ended June 30, 2010 versus the three month period ended June 30, 2009. Oil price realizations increased by 29% to $67.91 per barrel for the three month period ended June 30, 2010, compared to $52.69 per barrel for the same period in 2009. Total natural gas price realizations increased 78% to $3.91 per Mcf for the three month period ended June 30, 2010, compared to $2.20 per Mcf for the same period in 2009. Our increased oil production and, to a lesser extent, the increased pricing received for our products, for the period resulted in an increase in oil and gas revenue of $4.1 million, from approximately $2.0 million for the three-month period ended June 30, 2009 to $6.1 million for the same period in 2010, a 207% increase.

        The following table sets forth of the Company's financial results, capital resources and liquidity as of and for the three months ended June 30, 2010 as compared to the three months ended June 30, 2009.

Oil and Gas Revenue and Production

        During the three month period ended June 30, 2010, as compared to the same period in 2009, crude oil production volumes increased 147% due to new production from completion operations on our Dunn County, North Dakota operating area. Natural gas production volumes decreased 14% due to our decision to limit production on our Wyoming wells and declines in other gas well production. Oil and natural gas revenues increased by $4.1 million, or 207%, compared to the first quarter of 2009, primarily due to our increased volumes attributable to our recent well completions and, to a lesser extent, increased realized pricing for oil and natural gas in 2010 versus 2009. The increase in oil and gas revenue was 85% attributable to the increase in production volumes and 15% attributable to the increase in realized commodity prices.

Lease Operating Expenses

        The Company recorded workover, lease operating and production tax expense of approximately $1.5 million during the three month period ended June 30, 2010, as compared to approximately $344,000 during the same period in 2009. The increase is due to our increased lease operating expenses

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on the ten new wells in production as of June 30, 2010 that were not in production in 2009 and the related severance taxes paid related to the revenue received on the new wells production. A significant portion of the operating expense is related to the disposal of water in the early months of a well's production. Since a majority of the water is related to completion operations and is largely diminished after two to three months, the well's operating expenses decline over its early production period. Overall, we have continued to bring new wells online and, as a result of the water disposal costs, our total operating expenses reflect the added cost of water disposal.

Depletion, Depreciation and Amortization

        Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was approximately $1.5 million for the three month period ended June 30, 2010, compared to $532 thousand for the same period in 2009. DD&A expense increased during the quarter due to increased production for the new wells placed in service from the second quarter of 2009 through the second quarter of 2010.

Ceiling Test Impairment

        Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower of unproved properties that are subject to amortization. For the three months ended June 30, 2010 and June 30, 2009, respectively, no impairment charges were recorded.

General and Administrative Expense

        The Company's general and administrative costs were approximately $2.6 million for the three months ended June 30, 2010 compared to approximately $1.7 million for the same period in 2009. This 57% increase for the period is primarily due to adding additional employees in 2010 as the Company has increased its operational activities in the Williston Basin. We currently have 27 employees as compared to 16 at the end of 2009. Further, as we have grown our production base in the Williston Basin, we have established a regional office in Dickinson, North Dakota, that is staffed by permanent field employees that directly oversee our ongoing activities.

For the Six Months Ended June 30, 2010 compared to the Six Months Ended June 30, 2009

        The Company reported net income for the six months ended June 30, 2010 of approximately $1.6 million compared to a net loss of $2.2 million for the same period in 2009. The improvement from a net loss to net income is attributable to the new production from our Dunn Country, North Dakota Bakken wells, where our first wells began producing in the second quarter of 2009, and includes sales from three Bakken wells which came on to production during 2010. For the six months ending June 30, 2010, our volumes on a BOE basis increased 130% from 78,229 BOE in the first half of 2009 to 180,056 BOE during the first half of 2010. In addition, we realized increased prices for both oil and natural gas during the six month period ended June 30, 2010 versus the six month period ended June 30, 2009. Oil price realizations increased by 53% to $69.40 per barrel for the six month period ended June 30, 2010, compared to $45.48 per barrel for the same period in 2009. Total natural gas price realizations increased 77% to $4.60 per Mcf for the six month period ended June 30, 2010, compared to $2.60 per Mcf for the same period in 2009. Our increased oil production and, to a lesser extent, the increased pricing received for our products for the period resulted in an increase in oil and gas revenue of $9.0 million, from approximately $2.8 million to $11.8 million, a 328% increase in revenue for the six month period ended June 30, 2010 compared to the same period in 2009.

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        The following table sets forth the Company's financial results, capital resources and liquidity as of the six months ended June 30, 2010 as compared to the six months ended June 30, 2009.

Oil and Gas Revenue and Production

        During the six month period ended June 30, 2010, as compared to the same period in 2009, crude oil production volumes increased 217% due to new production from completion operations on our Dunn County, North Dakota operating area. Natural gas production volumes decreased 41% due to our decision to limit production on our Wyoming wells and natural declines in other gas well production. Oil and natural gas revenues increased by $9.0 million, or 328%, for the first half of 2010 compared to the first half of 2009, primarily due to our increased volumes attributable to our recent well completions and, to a lesser extent, increased realized pricing for oil and natural gas in 2010 versus 2009. The increase in oil and gas revenue was 83% attributable to the increase in production volumes and 17% attributable to the increase in realized commodity prices.

Lease Operating Expenses

        The Company recorded workover, lease operating and production tax expense of approximately $2.7 million during the six month period ended June 30, 2010, as compared to $492 thousand during the same period in 2009. The increase is due to our increased lease operating expenses on the ten new wells in production as of June 30, 2010 that were not in production in 2009 and the related severance taxes paid related to the revenue received on the new wells production. A significant portion of the operating expense is related to the disposal of water in the early months of a well's production. Since a majority of the water is related to completion operations and is largely diminished after two to three months, the well's operating expenses decline over its early production period. Overall, we have continued to bring new wells online and as a result of the water disposal costs our operating expenses reflect this added cost.

Depletion, Depreciation and Amortization

        DD&A was approximately $2.9 million, for the six month period ended June 30, 2010, compared to $888 thousand for the same period in 2009. DD&A expense increased during the quarter due to increased production for the new wells placed in service from the second quarter of 2009 through the second quarter of 2010.

Ceiling Test Impairment

        Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value,

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discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower of unproved properties that are subject to amortization. For the six months ended June 30, 2010, and June 30, 2009, respectively, no impairment charges were recorded.

General and Administrative Expense

        The Company's general and administrative costs were approximately $4.7 million for the six months ended June 30, 2010 compared to approximately $3.6 million for the same period in 2009. This 31% increase for the period is primarily due to adding additional employees in 2010 as the Company has increased its operational activities in the Williston Basin. We currently have 27 employees as compared to 16 at the end of 2009. Further, as we have grown our production base in the Williston Basin, we have established a regional office in Dickinson, North Dakota that is staffed by permanent field employees that directly oversee our ongoing activities.

Oil and Gas Properties

        As of June 30, 2010, we had several hundred lease agreements representing approximately 151,000 gross and 82,500 net acres, primarily in the Green River Basin and Williston Basin.

        As of June 30, 2010, we had an interest in approximately 56,000 gross acres and 35,000 net acres in the Bakken oil play located on the Fort Berthold Indian Reservation in Mountrail and Dunn Counties, N.D. The majority of our lands in this area are administered by the Bureau of Indian Affairs on behalf of the individual members of the Three Affiliated Tribes of the Fort Berthold Indian Reservation. Typically, these lands are acquired through a private negotiation with the individual land owners or the Three Affiliated Tribes and have a primary lease term of five years. The land owner typically retains an 18% landowner royalty. In most cases, these lands require an annual delay rental of $2.50 per net acre.

        As of June 30, 2010, we owned an interest in approximately 35,000 gross (22,500 net) acres in the Williston Basin outside the Fort Berthold Indian Reservation in Sheridan County, Montana, and McKenzie and Divide Counties, North Dakota. This acreage is prospective for Mission Canyon, Red River, Bakken and Three Forks formations.

        Our leasehold interests in the Vermillion Basin total approximately 41,000 gross and 8,800 net acres as of June 30, 2010.

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        The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of June 30, 2010.

        Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless (i) the existing lease is renewed, (ii) we have obtained production from the acreage subject to the lease prior to the end of the primary term, in which event the lease will remain in effect until the cessation of production or (iii) it is contained within a federal unit.

        The following table sets forth the gross and net acres of undeveloped land subject to leases that will expire either in 2010 or the following three years and have no options for renewal or are not included in federal units:

        The acreage expiring in 2010 consists primarily of lands located on the edges of the current drilling activity. We are evaluating some of these lands through our current drilling program, and we believe we can re-lease these lands as required for development on acceptable terms.

Commitments and Contingencies

        During the second quarter of 2008, the Company entered into contracts for the use of two new-build drilling rigs. The first rig was placed into operation in November 2008 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior to September 15, 2010. The contract can be extended by mutual consent of Kodiak and the drilling contractor at its termination. The estimated termination fee for this first rig is approximately $1.8 million as of June 30, 2010. The second rig was placed into operation in March 2010 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior to March 10, 2012. This

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contract can also be extended by mutual consent. The estimated termination fee for the second rig is approximately $4.8 million as of June 30, 2010. The Company is currently utilizing both rigs for drilling in the Williston Basin and expects to continue utilization through their respective terms.

        During the second quarter of 2010, the Company entered into a contract for the use of an additional drilling rig. The third rig is anticipated to be placed into operation in 2011 and entails a one-year drilling commitment or specific termination fees if the contract is terminated prior to delivery of the rig. It may also be extended by mutual consent. The estimated termination fee for this third rig is approximately $3.8 million as of June 30, 2010. The Company currently expects to utilize this rig in its operations in the Williston Basin. For a further discussion of our commitments and contingencies, see Note 5 to our financial statements included above, which is incorporated herein by reference.

Off Balance Sheet Arrangements

        The Company did not have any off balance sheet arrangements, as such term is defined in Item 303(a)(4)(ii) of Regulation S-K, at June 30, 2010 and December 31, 2009.

Critical Accounting Policies and Estimates

        Please see Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2009, which is incorporated herein by reference.

Recently Issued Accounting Pronouncements

        In January 2010, the FASB issued ASU 2010-03, Extractive Activities—Oil and Gas (Topic 932), to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. In April 2010, the FASB issued ASU 2010-14 which amends the guidance on oil and gas reporting in ASC 932.10.S99-1 by adding the Codification SEC Regulation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU 2010-14 are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments.

        In January 2010, the FASB issued ASU 2010-06, "Improving Disclosures About Fair Value Measurements", which provides amendments to fair value disclosures. ASU 2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. The revised guidance for transfers into and out of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010, with the amendments to Level 3 disclosures effective beginning after January 1, 2011. ASU 2010-06 concerns disclosure only. Both the current and future adoption does not have a material impact on the Company's financial position or results of operations.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

        Our primary market risk is market changes in oil and natural gas prices. Prospective revenues from the sale of products or properties will be impacted by oil and natural gas prices. A $1.00 per Mcf change in the market price of natural gas would have resulted in an approximate $50,805 change in our gross gas production revenue based on our production volumes for the three months ended June 30,

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2010. A $1.00 per barrel change in the market price of oil would have resulted in an approximate $81,926 change in our gross oil production revenue based on our production volumes for the three months ended June 30, 2010.

        We manage this commodity price risk exposure through the use of derivative financial instruments. Currently, we utilize "no premium" collars to reduce the effect of price changes on a portion of our future oil production. A collar requires us to pay the counterparty if the market price is above the ceiling price and requires the counterparty to pay us if the market price is below the floor price. At July 31, 2010, forecasted oil production of 200 Bbl/d for the remainder of 2010 and 400 Bbl/d for calendar year 2011 had been hedged.

        The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's wholly-owned subsidiary, Kodiak USA, has entered into the derivative contracts with two counterparties, and the Company is a guarantor of Kodiak USA. The Company has netting arrangements with the counterparties that provides for the offset of payables against receivables from separate derivative arrangements with each counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

        The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, these instruments may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions.

        The Company's commodity derivative contract as of June 30, 2010 is summarized below:

        Subsequent to June 30, 2010, the Company entered into an additional commodity derivative contract that is summarized below:

Interest Rate Risk

        We are exposed to changes in interest rates, which affect the interest earned on our cash and cash equivalents and the interest rate paid on our borrowings. We have not used interest rate derivative instruments to manage our exposure to interest rate changes.

        In May 2010, the Company (through its wholly-owned subsidiary) entered into a $200 million, four-year, revolving, senior secured credit facility. The outstanding principal balance of the revolving loan, together with all unpaid fees and expenses relating thereto, shall be due and payable no later than May 24, 2014. As of June 30, 2010, the Company had borrowed $5.0 million under this credit facility, and as of the time of this filing, the Company had borrowed $7.5 million thereunder.

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        Interest on the revolving loans is payable at the Adjusted LIBO rate for Eurodollar loans, plus a margin based on the daily unused portion of the facility. At June 30, 2010, the borrowing base for our credit facility was $20 million. Since we had borrowed $5 million under our credit facility at June 30, 2010, we were utilizing 25% of our available borrowing base. At that level of utilization, our credit facility required us to pay a margin of 2.50% on Eurodollar loans. The all-in interest rate that we were required to pay on the amounts borrowed under our credit facility under the Eurodollar loan election was 2.86%, as of June 30, 2010. A 10% increase in the rate would equal approximately 29 basis points. Such an increase would change our annual interest expense by approximately $14,300, assuming borrowed amounts under our credit facility had remained constant at $5 million.

        We also currently maintain a portion of our available cash in redeemable short term investments, classified as cash equivalents, and our reported interest income from these short term investments could be adversely affected by any material changes in U.S. dollar interest rates. A 10% change in the interest rate would have an approximate annual impact of $391,310 if all of our cash, as of June 30, 2010, had been invested in interest bearing notes.

ITEM 4.    CONTROLS AND PROCEDURES

        Under the supervision and with the participation of our management, we evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act as of June 30, 2010. On the basis of this review, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to give reasonable assurance that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure.

        There have not been any changes in the Company's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated by the SEC under the Exchange Act) during the Company's most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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PART II—OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

        From time to time, the Company is a party to routine litigation and proceedings that are considered part of the ordinary course of its business. The Company is not aware of any material current, pending, or threatened litigation.

ITEM 1A.    RISK FACTORS

        An investment in our common stock involves a high degree of risk. You should carefully consider the risks described in this Quarterly Report and the other documents we have filed with the SEC before deciding to invest in our common stock.

        This Quarterly Report also contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of a number of factors, including the risks described below and elsewhere in this Quarterly Report. See "Forward-Looking Statements" in this Quarterly Report.

Risks Related to the Company

Our current working capital, together with cash generated from anticipated production, will not be sufficient to support all our planned exploration and development opportunities.

        Our current working capital, together with cash generated from anticipated production, is only expected to be sufficient to support our currently anticipated exploration and development opportunities through 2010. If we realize lower than expected cash from production, either due to lower than anticipated production levels or a decline in commodity prices from recent levels, we would need to curtail our planned exploration and development activities or seek alternative sources of capital, including by means of entering into joint ventures with other exploration and production companies, sales of interests in certain of our properties or by undertaking additional financing activities (including through the issuance of equity or the incurrence of debt). We may not be able to access the capital markets or otherwise secure such additional financing on reasonable terms or at all, and financing may not continue to be available to us under our existing or new financing arrangements. If additional capital resources are unavailable, we may curtail our drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our business, financial condition and results of operation.

Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory and development drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

        Operations in the Bakken and the Three Forks formations involve utilizing the latest drilling and completion techniques as developed by ourselves and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length

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of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage.

        Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Bakken and Three Forks formations is limited. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Substantially all of our producing properties and operations are located in the Williston Basin region, making us vulnerable to risks associated with operating in one major geographic area.

        As of December 31, 2009, approximately 96% of our proved reserves and approximately 67% of our production were located in the Williston Basin in northeastern Montana and northwestern North Dakota. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

The ongoing financial uncertainty in the U. S. and globally could negatively impact the prices for oil and natural gas, limit access to the credit and equity markets and increase the cost of capital, and may have other negative consequences that we cannot predict.

        The ongoing financial uncertainty in the U.S. and globally could create financial challenges if conditions do not improve. Our internally generated cash flow and cash on hand historically have not been sufficient to fund our expenditures, and we have relied on the capital markets and sales of non-core assets to provide us with additional capital. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital. If our cash flow from operations is less than anticipated and our access to capital is restricted, we may be required to reduce our operating and capital budget, which could have a material adverse effect on our results and future operations. Ongoing uncertainty may also reduce the values we are able to realize in asset sales or other transactions we may engage in to raise capital, thus making these transactions more difficult to consummate and less economic. Additionally, demand for oil and natural gas may deteriorate and result in lower prices for oil and natural gas, which could have a negative impact on our revenues. Lower prices could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations.

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Certain covenants under our credit facility could limit our flexibility and prevent us from taking certain actions. In addition, there can be no assurance that we will be able to generate sufficient cash flows to repay our debt obligations under our credit facility. The occurrence of any of the foregoing could adversely affect our business, results of operations and financial condition.

        Our new credit facility contains a number of affirmative, negative, and financial covenants that limit our ability to take certain actions and require us to comply with specified financial ratios and other performance covenants. Such provisions may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. No assurance can be provided that we will not violate the covenants of our secured credit facility in the future. If we are unable to comply with applicable covenants in the future, our lender could pursue its contractual remedies under the credit facility, including requiring the immediate repayment in full of all amounts outstanding and foreclosing on the oil and gas properties mortgaged to our lender. Additionally, we cannot be certain that, if the lender demands immediate repayment of any amounts outstanding, we would be able to secure adequate or timely replacement financing on acceptable terms or at all.

Availability under our credit facility is based on a borrowing base which is subject to redetermination by our lenders. If our borrowing base is reduced, we may be required to repay amounts outstanding under our credit facility.

        Our ability to make payments due under our credit facility will depend upon our future operating performance, which is subject to general economic and competitive conditions and to financial, business and other factors, many of which we cannot control. In addition, our borrowing base is subject to semi-annual redetermination by our lender based on its valuation of our proved reserves and the lender's internal criteria. In the event the amount outstanding under our credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings on an accelerated basis. If we do not have sufficient funds on hand for repayment in such event, or to service our debt obligations generally, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility, sell assets or sell additional shares of securities. We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all. In addition, our credit agreement may limit our ability to take certain of such actions. Failure to make the required repayment could result in a default under our credit facility. Our failure to generate sufficient funds to pay our debts or to undertake any of these actions successfully, or to comply with the covenants under our credit facility mentioned above, could materially adversely affect our business, results of operations and financial condition.

We may incur termination fees related to our drilling rig contracts, which could impair our working capital and have a material adverse effect on our business, operations and liquidity.

        We have three contracts currently in place for the use of drilling rigs. As of May 31, 2010, the estimated termination fees are approximately $2.5 million for the first rig contract that expires in September 2010, approximately $4.9 million for the second rig contract that expires in March 2012 and approximately $3.8 million for the third rig contract that expires in October 2011. If we incur any of these fees as a result of terminating one or more of the drilling rig contracts, our working capital could be impaired. Such event could accelerate the need we may have for additional capital funding and may adversely affect our ability to comply with our credit facility covenants and/or result in a decrease in our borrowing base, which could result in the acceleration of our debt repayment obligations. Any of such events could have a material adverse effect on our business, operations and liquidity.

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We may not be able to successfully drill wells that produce oil or natural gas in commercially viable quantities.

        We cannot assure you that each well we drill will produce commercial quantities of oil and natural gas. The total cost of drilling, completing and operating a well is uncertain before drilling commences. Overruns in budgeted expenditures are a common risk that can make a particular project uneconomical. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling each well whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. Our use of seismic data is subject to interpretation and may not accurately identify the presence of natural gas and oil. Further, many factors may curtail, delay or cancel drilling, including the following:

•

delays and restrictions imposed by or resulting from compliance with regulatory requirements;



•

pressure or irregularities in geological formations;



•

shortages of or delays in obtaining equipment and qualified personnel;



•

equipment failures or accidents;



•

adverse weather conditions;



•

reductions in oil and natural gas prices;



•

land title problems; and



•

limitations in the market for oil and natural gas.

        Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. The occurrence of any of these events could negatively affect our ability to successfully drill wells that produce oil or natural gas in commercially viable quantities.

Our commodity derivative arrangements could result in financial losses or could reduce our earnings.

        From time to time, we enter into financial hedge arrangements (commodity derivative agreements) in order to manage our commodity price risk and to provide a more predictable cash flow from operations. We do not intend to designate our derivative instruments as hedges for accounting purposes. The fair value of our derivative instruments will be marked to market at the end of each quarter and the resulting unrealized gains or losses due to changes in the fair value of our derivative instruments will be recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

        Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows.

        Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

•

production is less than the volume covered by the derivative instruments;

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•

the counter-party to the derivative instrument defaults on its contract obligations;



•

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or



•

the steps we take to monitor our derivative financial instruments do not detect and prevent transactions that are inconsistent with the Company's risk management strategies.

        In addition, depending on the type of derivative arrangements we enter, the agreements could limit the benefit we would receive from increases in oil prices. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil prices.

We intend to continue to place hedges on future production and if we encounter difficulties meeting that production, we may not realize the originally anticipated cash flows.

        To the extent that our oil production is less than the production required under our commodity derivative contracts, our cash flow may be adversely affected if energy prices rise above the prices for the forward-looking sales. In this case, we would be required to make payments to the purchaser of the forward-looking sale equal to the difference between the current commodity price and that in the sales contract multiplied by the physical volume of the shortfall. There is the risk that production estimates could be inaccurate or that unanticipated problems could cause the production to be less than the amount anticipated, causing us to make payments to the purchasers pursuant to the terms of the commodity derivative contracts.

We have historically incurred losses and cannot assure investors as to future profitability.

        We have historically incurred losses from operations during our history in the oil and natural gas business. As of June 30, 2010, we had a cumulative deficit of $104 million. While we have developed some of our properties, many of our properties are in the exploration stage, and to date we have established a limited volume of proved reserves on our properties. Our ability to be profitable in the future will depend on successfully implementing our acquisition, exploration, development and production activities, all of which are subject to many risks beyond our control. We cannot assure you that we will successfully implement our business plan or that we will achieve commercial profitability in the future. Even if we become profitable on an annual basis, we cannot assure you that our profitability will be sustainable or increase on a periodic basis. In addition, should we be unable to continue as a going concern, realization of assets and settlement of liabilities in other than the normal course of business may be at amounts significantly different from those in the financial statements included in our most recently filed annual report on Form 10-K for the year ended December 31, 2009 and quarterly report on Form 10-Q for the quarter ended June 30, 2010.

The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, the present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

        Our most recently filed annual report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves. The December 31, 2009 reserve estimate was prepared by Netherland Sewell & Associates, Inc. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development and operating expenses, and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition,

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we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

        You should not assume that the present value of future net revenues referred to in our annual report on Form 10-K is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the un-weighted average of the closing prices during the first day of each of the twelve months preceding the end of the fiscal year. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any change in consumption by oil or natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of our oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor nor does it reflect discount factors used in the market place for the purchase and sale of oil and natural gas.

Our reserves and production will decline, and unless we replace our oil and natural gas reserves, our business, financial condition and results of operations will be adversely affected.

        Producing oil and natural gas reserves ultimately results in declining production that will vary depending on reservoir characteristics and other factors. Thus, our future oil and natural gas production and resulting cash flow and earnings are directly dependent upon our success in developing our current reserves and finding additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Our business involves numerous operating hazards and exposure to significant weather and climate risks. We have not insured and cannot fully insure against all risks related to our operations, which could result in substantial claims for which we are underinsured or uninsured.

        We have not insured and cannot fully insure against all risks and have not attempted to insure fully against risks where coverage is prohibitively expensive. Our exploration, drilling and other activities are subject to risks such as:

•

adverse weather conditions, natural disasters and other environmental disturbances;



•

fires and explosions;



•

environmental hazards, such as uncontrollable flows of natural gas, oil, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;



•

abnormally pressured formations;



•

mechanical failures of drilling equipment;



•

personal injuries and death, including insufficient worker compensation coverage for third-party contractors who provide drilling services; and



•

acts of terrorism.

        In particular, our operations in North Dakota, Montana and Wyoming are conducted in areas subject to extreme weather conditions and often in difficult terrain. Primarily in the winter and spring, our operations are often curtailed because of cold, snow and wet conditions. Unusually severe weather could further curtail these operations, including drilling of new wells or production from existing wells, and depending on the severity of the weather, could have a material adverse effect on our business,

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financial condition and results of operations. In addition, weather conditions and other events could temporarily impair our ability to transport our oil and natural gas production.

        We do not carry business interruption insurance coverage. Losses and liabilities arising from uninsured and underinsured events, which could arise from even one catastrophic accident, could materially and adversely affect our business, results of operations and financial condition.

We have limited control over activities in properties we do not operate, which could reduce our production and revenues, affect the timing and amounts of capital requirements and potentially result in a dilution of our respective ownership interest in the event we are unable to make any required capital contributions.

        We do not operate all of the properties in which we have an interest. As a result, we may have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. For all of the properties that are operated by others, we are dependent on their decision-making with respect to day-to-day operations over which we have little control. The failure of an operator of wells in which we have an interest to adequately perform operations, or an operator's breach of applicable agreements, could reduce production and revenues we receive from that well. The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including:

•

timing and amount of capital expenditures;



•

expertise and financial resources; and



•

inclusion of other participants.

        In particular, we are party to a joint venture agreement with a third party that relates to the development of certain of our properties in Dunn County, North Dakota. Pursuant to this agreement, we are required to pay 50% of the drilling expenses attributable to our joint venture's proportionate interest incurred in the area of mutual interest. In 2010, we allocated $12 million of our capital budget toward the payment of these drilling expenses. We have recently been advised by our joint venture partner that it intends to add a second drilling rig in 2011, which would require us to make significantly higher capital contributions to satisfy our proportionate share of the exploration costs. If such capital contributions are required, we may not be able to obtain the financing necessary to satisfy our obligations or we may have to reallocate our anticipated capital expenditure budget. In the event that we do not participate in future capital contributions with respect to this joint venture agreement or any other agreements relating to properties we do not operate, our respective ownership interest could be diluted.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

        We use independent contractors to provide us with technical assistance and services. We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production. In addition, we rely upon the services of other third parties to explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the activities and business practices of these providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially and adversely affect our business, results of operations and financial condition.

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We depend on a limited number of customers for sales of our oil. We are exposed to credit risk if one or more of our significant customers becomes insolvent and fails to pay amounts owed to us. To the extent our customers cease to be creditworthy, our revenues could decline.

        During the year ended December 31, 2009, over 55% of our oil production was sold to one customer. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers, would purchase all or substantially all of our production in the event that our major customer curtailed its purchases. It is possible that one or more of our customers will become financially distressed and default on their obligations to the Company. Furthermore, bankruptcy of one or more of our customers, or some other similar procedure, might make it difficult for us to collect all or a significant portion of amounts owed by the customers. Our inability to collect our accounts receivable could have a material adverse effect on our results of operations.

        The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. Although we have not been directly affected, we are aware that some refiners have filed for bankruptcy protection, which has caused the affected producers to not receive payment for the production that was delivered. If economic conditions continue to deteriorate, it is likely that additional, similar situations will occur which will expose us to added risk of not being paid for oil or natural gas that we deliver. We do not obtain credit protections such as letters of credit, guarantees or prepayments from our purchasers. We are unable to predict what impact the financial difficulties of any of our purchasers may have on our future results of operations and liquidity.

Our interests are held in the form of leases that we may be unable to retain and the title to our properties may be defective.

        Our properties are held under leases and working interests in leases. Generally, the leases we are a party to provide for a fixed term, but contain a provision that allows us to extend the term of the lease so long as we are producing oil or natural gas in quantities to meet the required payments under the lease. If we or the holder of a lease fails to meet the specific requirements of the lease regarding delay rental payments, continuous production or development, or similar terms, portions of the lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each lease will be met. The termination or expiration of our leases or the working interests relating to leases may reduce our opportunity to exploit a given prospect for oil and natural gas production and thus have a material adverse effect on our business, results of operation and financial condition.

        It is our practice in acquiring oil and natural gas leases or interests in oil and natural gas leases not to undergo the expense of retaining lawyers to fully examine the title to the interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who actually do the field work in examining records in the appropriate governmental office before attempting to place under lease a specific interest. We believe that this practice is widely followed in the oil and natural gas industry.

        Prior to drilling a well for oil and natural gas, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to hire a lawyer to examine the title to the unit within which the proposed oil and natural gas well is to be drilled. Frequently, as a result of such examination, curative work must be done to correct deficiencies in the marketability of the title. The work entails expense and might include obtaining an affidavit of heirship or causing an estate to be administered. The examination made by the title lawyers may reveal that the oil and natural gas lease or leases are worthless, having been purchased in error from a person who is not the owner of the mineral interest desired. In such instances, the amount paid for such oil and natural gas lease or leases may be lost.

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Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses. Our large inventory of undeveloped acreage and large percentage of undeveloped proved reserves may create additional economic risk.

        One of our growth strategies is to pursue selective acquisitions of undeveloped leaseholder oil and natural gas reserves. If we choose to pursue an acquisition, we will perform a review of the target properties that we believe is consistent with industry practices. However, these reviews are inherently incomplete. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties.

        Our success is largely dependent upon our ability to develop our large inventory of future drilling locations, undeveloped acreage and undeveloped reserves. As of December 31, 2009, approximately 68% of our total proved reserves were undeveloped. To the extent our drilling results are not as successful as we anticipate, natural gas and oil prices decline, or sufficient funds are not available to drill these locations and reserves, we may not capture the expected or projected value of these properties. In addition, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.

Increases in interest rates could adversely affect our results of operations.

        As of June 30, 2010, we had $5 million borrowed under a credit facility. Subsequent to June 30, we borrowed an additional $2.5 million under this credit facility, and we may borrow additional amounts in the future. Our credit facility is subject to a floating interest rate, which may vary in line with the movements in short term interest rates. As a result, our interest expenses may increase significantly if short term interest rates increase. To the extent that we rely on our credit facility, an increase in the interest rate under our facility would increase the borrowing cost of our outstanding debt.

We depend on our key management personnel and technical experts and the loss any of these individuals could adversely affect our business.

        If we lose the services of our key management personnel, technical experts or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could suffer. We have assembled a team of engineers and geologists who have considerable experience in applying advanced horizontal drilling and completion technology to explore for and to develop oil and natural gas. We depend upon the knowledge, skill and experience of these experts to assist us in improving the performance and reducing the risks associated with our participation in oil and natural gas exploration and development projects. In addition, the success of our business depends, to a significant extent, upon the abilities and continued efforts of our management.

Our officers and directors may become subject to conflicts of interest.

        Some of our directors and officers may also become directors, officers, contractors, shareholders or employees of other companies engaged in oil and natural gas exploration and development. To the extent that such other companies may participate in ventures in which we may participate, our directors

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may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. In the event that such a conflict of interest arises at a meeting of our directors, a director who has such a conflict will declare his interest and abstain from voting for or against the approval of such participation or such terms. In appropriate cases, we will establish a special committee of independent directors to review a matter in which several directors, or management, may have a conflict. From time to time, several companies may participate in the acquisition, exploration and development of oil and natural gas properties thereby allowing for their participation in larger programs, permitting involvement in a greater number of programs and reducing financial exposure in respect of any one program. A particular company may assign all or a portion of its interest in a particular program to another of these companies due to the financial position of the company making the assignment.

        In accordance with the laws of the Yukon Territory, our directors are required to act honestly, in good faith and in the best interests of our company. In determining whether or not we will participate or acquire an interest in a particular program, our officers will primarily consider the potential benefits to our company, the degree of risk to which we may be exposed and our financial position at the time.

Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts.

        Our future rate of growth greatly depends on the success of our exploratory drilling program. Exploratory drilling involves a higher degree of risk that we will not encounter commercially productive oil or natural gas reservoirs than developmental drilling. We may not be successful in our future drilling activities because, even with the use of advanced horizontal drilling and completion techniques, 3-D seismic and other advanced technologies, exploratory drilling is a speculative activity.

Marketing and transportation constraints in the Williston Basin could adversely affect our operations and result in significant fluctuations in our realized prices for oil and, to a lesser extent, natural gas.

        We deliver oil and natural gas through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future. In particular, the Williston Basin crude oil marketing and transportation environment has historically been characterized by periods when oil production has surpassed local transportation and refining capacity. These factors could force us to shut-in producing wells, delay the commencement of production, or discontinue development plans for some of our properties. In addition, these factors have resulted, and could continue to result, in substantial discounts in the price received for crude oil compared to benchmark prices, such as the West Texas Intermediate crude oil prices. The persistence of such constraints could have a material adverse effect on our financial condition and results of operations.

We are subject to the risks associated with our prior business activities.

        Additional risks may exist because of our prior business activities. Prior to current management's acquisition of control of substantially all of our common stock, we engaged in a number of businesses, including mining operations and marketing of fire retardant operations. For a period of years prior to current management's acquisition of control of us, we had no business operations. Although current management performed a due diligence review, we may still be exposed to undisclosed liabilities, including environmental liabilities, resulting from the prior operations of our company and we could incur losses, damages or other costs as a result.

Our competitors include larger, better financed and more experienced companies.

        The oil and natural gas industry is intensely competitive, and we must compete against larger companies that may have greater financial and technical resources than us and substantially more

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experience in our industry. Their competitive advantages may negatively impact our ability to acquire prospective properties, develop reserves, attract and retain quality personnel and raise capital. Their competitive advantages may also better enable our competitors to sustain the impact of higher exploration and production costs, oil and natural gas price volatility, productivity variances among properties, overall industry cycles and other factors related to our industry.

Operations on the Fort Berthold Indian Reservation of the Three Affiliated Tribes in North Dakota are subject to various federal and tribal regulations and laws, any of which may increase our costs and delay our operations.

        Various federal agencies within the U.S. Department of the Interior, particularly the Minerals Management Service and the Bureau of Indian Affairs, along with the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. In addition, the Three Affiliated Tribes is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.

Our level of indebtedness may increase and reduce our financial flexibility.

        As of June 30, 2010, we had $5 million borrowed under a credit facility. Subsequent to June 30, 2010, we borrowed an additional $2.5 million under this credit facility, which has an initial borrowing capacity of $20 million. In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

        Our level of indebtedness could affect our operations in several ways, including the following:

•

a significant portion of our cash flows could be used to service our indebtedness;



•

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;



•

the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;



•

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;



•

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;



•

a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then outstanding bank borrowings; and



•

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

        A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other

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factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

        In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.

        We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

•

recoverable reserves;



•

future oil and natural gas prices and their appropriate differentials;



•

development and operating costs; and



•

potential environmental and other liabilities.

        The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.

        Significant acquisitions and other strategic transactions may involve other risks, including:

•

diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;



•

challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;



•

difficulty associated with coordinating geographically separate organizations; and



•

challenge of attracting and retaining personnel associated with acquired operations.

        The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any

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significant business activities are interrupted as a result of the integration process, our business could suffer.

If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be lower than we expect.

        The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

Risks Relating to Our Industry

Oil and natural gas prices are volatile. A substantial or extended decline in oil prices and, to a lesser extent, natural gas prices, could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

        Historically, the markets for natural gas and oil have been volatile and they are likely to continue to be volatile. As with most other companies involved in resource exploration and development, we may be adversely affected by future increases in the costs of conducting exploration, development and resource extraction that may not be fully offset by increases in the price received on sales of oil or natural gas. Our focus on exploration activities therefore exposes us to greater risks than are generally encountered in later-stage oil and natural gas property development companies.

        The economic success of any drilling project will depend on numerous factors, including:

•

our ability to drill, complete and operate wells;



•

our ability to estimate the volumes of recoverable reserves relating to individual projects;



•

rates of future production;



•

future commodity prices; and



•

investment and operating costs and possible environmental liabilities.

        Wide fluctuations in natural gas and oil prices may result from relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and other factors that are beyond our control, including:

•

worldwide and domestic supplies of natural gas and oil;



•

weather conditions;



•

the level of consumer demand;



•

the price and availability of alternative fuels;



•

the proximity and capacity of natural gas pipelines and other transportation facilities;



•

the price and level of foreign imports;



•

domestic and foreign governmental regulations and taxes;

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•

the nature and extent of regulation relating to carbon dioxide and other greenhouse gas emissions;



•

the actions of the Organization of Petroleum Exporting Countries;



•

political instability or armed conflict in oil-producing regions; and



•

overall domestic and global economic conditions.

        Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

        Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas, that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall, as was the case in 2008 and 2007. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

Oil and natural gas are commodities subject to price volatility based on many factors outside the control of producers, and low prices may make properties uneconomic for future production.

        Oil and natural gas are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices a producer may expect and its level of production depend on numerous factors beyond its control, such as:

•

changes in global supply and demand for oil and natural gas;



•

economic conditions in the United States and Canada;



•

the actions of the Organization of Petroleum Exporting Countries, or OPEC;



•

government regulation;



•

the price and quantity of imports of foreign oil and natural gas;



•

political conditions, including embargoes, in oil- and natural gas-producing regions;



•

the level of global oil and natural gas inventories;



•

weather conditions;



•

technological advances affecting energy consumption; and



•

the price and availability of alternative fuels.

        Lower oil and natural gas prices may not only decrease revenues on a per unit basis, but also may reduce the amount of oil and natural gas that can be economically produced. Lower prices will also negatively affect the value of proved reserves.

        To attempt to reduce our price risk, in 2010, we implemented a strategy to hedge a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil would have a material adverse effect on our financial condition and results of operations.

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Lower oil and natural gas prices may cause us to record ceiling test write-downs.

        We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a "full cost ceiling" which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a "ceiling test write-down." This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders' equity. During 2009 and 2008, we recognized approximately $0 and $47.5 million, respectively, in ceiling test write-downs. We may recognize write-downs in the future if commodity prices continue to decline or if we experience substantial downward adjustments to our estimated proved reserves.

Conducting operations in the oil and natural gas industry subjects us to complex laws and regulations that can have a material adverse effect on the cost, manner and feasibility of doing business.

        Companies that explore for and develop, produce and sell oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax and environmental laws and the corresponding regulations, and are required to obtain various permits and approvals from federal, state and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

•

water discharge and disposal permits for drilling operations;



•

drilling bonds;



•

drilling permits;



•

reports concerning operations;



•

air quality, noise levels and related permits;



•

spacing of wells;



•

rights-of-way and easements;



•

unitization and pooling of properties;



•

gathering, transportation and marketing of oil and natural gas;



•

taxation; and



•

waste transport and disposal permits and requirements.

        Failure to comply with these laws may result in the suspension or termination of operations and subject us to liabilities and administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, these laws could change in ways that substantially increase the costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition and results of operations.

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The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

        In 2010, we implemented a strategy to hedge a portion of our crude oil and natural gas production. Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. The proposed legislation contains provisions that would prohibit private energy commodity derivative and hedging transactions by expanding the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including natural gas and oil, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under the proposed legislation, the CFTC's expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The CFTC is considering whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Our operations are subject to environmental, health and safety laws and regulations that may expose us to significant costs and liabilities.

        Our oil and natural gas exploration and production operations are subject to stringent and complex federal, state, local and tribal laws and regulations governing health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations include, but are not limited to, the federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability Act, the Safe Drinking Water Act, the Occupational Safety and Health Act and their state counterparts and similar statutes, which provide for civil, criminal and administrative penalties and other sanctions for violation of their requirements.

        These laws and regulations may impose numerous obligations on us and our operations including by requiring us to obtain permits before conducting drilling or underground injection activities; restricting the types, quantities and concentration of materials that we can release into the environment; limiting or prohibiting drilling activities on certain lands lying within wilderness, wetlands and other protected areas; subjecting us to specific health and safety requirements addressing worker protection; imposing substantial liabilities on us for pollution resulting from our operations; and requiring us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, and their interpretation and enforcement of these laws, regulations and permits have tended to become more stringent over time. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory, remedial or monitoring obligations; and the issuance of injunctions limiting or prohibiting some or all of our operations.

        There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations because of our handling of petroleum hydrocarbons and wastes; air emissions and wastewater discharges related to our operations; our ownership, lease or operation of real property;

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and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of contamination at properties we currently own, lease or operate or have owned, leased or operated in the past. These laws often impose liability even if the owner, lessee or operator was not responsible for the contamination, or the contamination resulted from actions taken in compliance with all applicable laws in effect at the time. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may bring claims against us for property damage or personal injury, including as a result of exposure to hazardous materials, or to enforce compliance with, or seek damages under, applicable environmental laws and regulations. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and such changes could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.

The regulations of "over-the-counter" derivatives introduced by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") could adversely impact our hedging strategy.

        Through its comprehensive new regulatory regime for derivatives, the Dodd-Frank Act will impose mandatory clearing, exchange-trading and margin requirements on many derivatives transactions (including formerly unregulated over-the-counter derivatives) in which we may engage. The Dodd-Frank Act also creates new categories of regulated market participants who will be subject to significant new capital, registration, recordkeeping, reporting, disclosure, business conduct and other regulatory requirements. The details of these requirements and the parameters of these categories remain to be clarified through rulemaking and interpretations by the CFTC, the SEC, the Federal Reserve and other regulators in a regulatory implementation process which is expected to take a year or more to complete.

        Nonetheless, based on information available as of the date of this prospectus, the possible effect of the Dodd-Frank Act will be to increase our overall costs of entering into derivatives transactions. In particular, new margin requirements, position limits and capital charges, even if not directly applicable to us, may cause an increase in the pricing of derivatives transactions sold by market participants to whom such requirements apply. Administrative costs, due to new requirements such as registration, recordkeeping, reporting, and compliance, even if not directly applicable to us, may also be reflected in higher pricing of derivatives. New exchange-trading and trade reporting requirements may lead to reductions in the liquidity of derivative transactions, causing higher pricing or reduced availability of derivatives, adversely affecting the performance of our hedging strategies.

        The Dodd-Frank Act could result in the cost of executing our hedging strategy increasing significantly, which could potentially result in an undesirable decrease in the amount of oil production we hedge. If our hedging costs increase and we are required to post cash collateral, our business would be adversely affected as a result of reduced cash flow and reduced liquidity. Additionally, in the event that we hedge lower quantities in response to higher hedging costs and increased margin requirements, our exposure to changes in commodity prices would increase, which could result in decreased cash flows.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

        Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock

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formations to stimulate natural gas production. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, such legislation, if adopted, or similar requirements at the state or local level, could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and doing business.

Changes in tax laws may impair our results of operations and adversely impact the value of our common stock.

        In February 2009, the Obama administration released its budget proposals for the fiscal year 2010, which included numerous proposed tax changes. In April 2009, legislation was introduced to further these objectives, and in February 2010, the Obama administration released similar budget proposals for the fiscal year 2011. Among the changes contained in the budget proposals is the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) the repeal of the passive loss exception for working interests in oil and gas properties. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could adversely affect the amount of our taxable income or loss and could have a negative impact on the value of our common stock.

Exploration and drilling operations are subject to significant environmental regulation, including those related to climate and emission of "greenhouse gases," which may increase costs or limit our ability to develop our properties.

        We may encounter hazards incident to the exploration and development of oil and natural gas properties, such as accidental spills or leakage of petroleum liquids and other unforeseen conditions. We may be subject to liability for pollution and other damages due to hazards that we cannot insure against due to prohibitive premium costs or for other reasons. Governmental regulations relating to environmental matters could also increase the cost of doing business or require alteration or cessation of operations in some areas.

        Existing and possible future environmental legislation, regulations and actions, including those related to climate and emissions of "greenhouse gases," could give rise to additional expenses, capital expenditures, restrictions and delays in our activities, the extent of which we cannot predict. In addition, climate change laws and regulations may adversely affect demand for the fossil fuels we produce, including by increasing the cost of combusting fossil fuels and by creating incentives for the use of alternative fuels and energy. Regulatory requirements and environmental standards are subject to constant evaluation and may be significantly increased, which could materially and adversely affect our business or our ability to develop our properties on an economically feasible basis. Before development and production can commence on any properties, we must obtain regulatory and environmental approvals. We cannot assure you that we will obtain such approvals on a timely basis or at all. The cost of compliance with changes in governmental regulations has the potential to reduce the profitability of our operations and preclude entirely the economic development of a specific property.

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The oil and natural gas industry is subject to significant competition, which may increase costs or otherwise adversely affect our ability to compete.

        Oil and natural gas exploration is intensely competitive and involves a high degree of risk. In our efforts to acquire oil and natural gas producing properties, we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also conduct refining and petroleum marketing operations on a worldwide basis. Our ability to compete for oil and natural gas producing properties will be affected by the amount of funds available to us, information available to us and any standards established by us for the minimum projected return on investment. Our products will also face competition from alternative fuel sources and technologies.

Our operations and demand for our products are affected by seasonal factors, which may lead to fluctuations in our operating results.

        Our operating results are likely to vary due to seasonal factors. Demand for oil and natural gas products will generally increase during the winter because they are often used as heating fuels. The amount of such increased demand will depend to some extent upon the severity of winter. Because of the seasonality of our business and continuous fluctuations in the prices of our products, our operating results are likely to fluctuate from period to period.

The lack of availability or high cost of drilling rigs, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

        Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies tend to increase, in some cases substantially. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases within a geographic area. If increasing levels of exploration and production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel were particularly severe in the areas in which we operate, we could be materially and adversely affected.

Risks Relating to Our Common Stock

Future sales or other issuances of our common stock could depress the market for our common stock.

        On July 14, 2008, we filed a shelf registration statement on Form S-3 (SEC file No. 333-152311), which was declared effective by the SEC on July 24, 2008. Under this shelf registration statement, we have raised funds and may seek to raise additional funds through one or more public offerings of our common stock, in amounts and at prices and terms determined at the time of the offering. Any sales of large quantities of our common stock could reduce the price of our common stock, and, to the extent that we raise additional capital by issuing equity securities pursuant to our effective shelf registration statements or otherwise, our existing stockholders' ownership will be diluted.

Our common stock has a limited trading history and has experienced price and volume volatility.

        Our common stock has been trading on the NYSE Amex since June 21, 2006. Prior to listing on the NYSE Amex, our common stock traded on the TSX Venture Exchange, or TSX-V, beginning

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September 28, 2001. The price of our common stock may be impacted by any of the following, some of which may have little or no relation to our company or industry:

•

the breadth of our stockholder base and extent to which securities professionals follow our common stock;



•

investor perception of our Company and the oil and natural gas industry, including industry trends;



•

domestic and international economic and capital market conditions, including fluctuations in commodity prices;



•

responses to quarter-to-quarter variations in our results of operations;



•

announcements of significant acquisitions, strategic alliances, joint ventures or capital commitments by us or our competitors;



•

additions or departures of key personnel;



•

sales or purchases of our common stock by large stockholders or our insiders;



•

accounting pronouncements or changes in accounting rules that affect our financial reporting; and



•

changes in legal and regulatory compliance unrelated to our performance.

        In addition, the stock market in general and the market for natural gas and oil exploration companies in particular have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating results or asset values of those companies. These broad market and industry factors may seriously impact the market price and trading volume of our common shares regardless of our actual operating performance.

We have not paid cash dividends on our common stock and do not anticipate paying any dividends on our common stock in the foreseeable future.

        We do not anticipate paying cash dividends on our common stock in the foreseeable future. Payment of future cash dividends, if any, will be at the discretion of our board of directors and will depend on our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our board of directors considers relevant. Furthermore, our credit facility with our lender prohibits us from paying dividends with respect to our common stock. Accordingly, investors may only see a return on their investment if the value of our securities appreciates.

Our constating documents permit us to issue an unlimited number of shares without shareholder approval.

        Our Articles of Continuation permit us to issue an unlimited number of shares of our common stock. Subject to the requirements of any exchange on which we may be listed, we will not be required to obtain the approval of shareholders for the issuance of additional shares of our common stock. In 2005, we issued 20,671,875 shares of our common stock for net proceeds of $17,879,673. In 2006, we issued 31,589,268 shares of our common stock for net proceeds of $83,209,451. In 2008, we issued 6,820,000 shares of our common stock for net proceeds of $17,471,488. In 2009 we issued 23,400,000 shares of our common stock for net proceeds of $35,731,122. Any further issuances of shares of our common stock from our treasury will result in immediate dilution to existing shareholders and may have an adverse effect on the value of their shareholdings.

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Sales, or the availability for sale, of substantial amounts of our common stock could adversely affect the value of our common stock.

        No prediction can be made as to the effect, if any, that future sales of our common stock, or the availability of common stock for future sales, will have on the market price of our common stock. We have several stockholders that hold a significant number of shares of our common stock. Sales of substantial amounts of our common stock in the public market and the availability of shares for future sale, including by one or more of our significant stockholders or shares of our common stock issuable upon exercise of outstanding options to acquire shares of our common stock, could adversely affect the prevailing market price of our common stock. This in turn would adversely affect the fair value of the common stock and could impair our future ability to raise capital through an offering of our equity securities.

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

        None.

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

        None.

ITEM 4.    RESERVED

ITEM 5.    OTHER INFORMATION

        None.

ITEM 6.    EXHIBITS

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SIGNATURES

        Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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