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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2008

Commission File No. 001-32920

(Exact name of registrant as specified in its charter)

1625 Broadway, Suite 250
Denver, Colorado 80202
(Address of principal executive offices, including zip code)

303-592-8075
(Registrant's telephone number, including area code)

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

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of "accelerated filer", large accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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

        88,084,431 shares, no par value, of the Registrant's Common Stock were issued and outstanding as of July 31, 2008.

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KODIAK OIL & GAS CORP.

INDEX

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PART 1—FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

SEE ACCOMPANYING NOTES

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KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

SEE ACCOMPANYING NOTES

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

SEE ACCOMPANYING NOTES

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization

Description of Operations

        Kodiak Oil & Gas Corp. and its subsidiary ("Kodiak" or the "Company") is a public company listed for trading on the American Stock Exchange (AMEX) and whose corporate headquarters are located in Denver, Colorado, USA. The Company is an independent energy company engaged in the exploration, exploitation, development, acquisition and production of natural gas and crude oil entirely in the western United States.

        The Company was incorporated (continued) in the Yukon Territory on September 28, 2001.

Note 2—Basis of Presentation and Significant Accounting Policies

Basis of Presentation

        The condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. All significant inter-company balances and transactions have been eliminated in consolidation. The majority of the Corporation's business is transacted in US dollars and, accordingly, the financial statements are expressed in US dollars.

        These unaudited interim financial statements have been prepared in accordance with U.S. generally accepted accounting principles ("GAAP") for interim financial information and reflect our condensed consolidated financial position as of December 31, 2007 and June 30, 2008. These statements also show our condensed consolidated statement of income for the three and six months ended June 30, 2007 and 2008 and our condensed consolidated statement of cash flows for the six months ended June 30, 2007 and 2008. These statements include all normal recurring adjustments that we believe are necessary to fairly state our financial position, operating results and cash flows. Because all of the disclosures required by U.S. generally accepted accounting principles for annual consolidated financial statements are not included herein, condensed consolidated financial statements should be read in conjunction with the Company's audited consolidated financial statements included in the Annual Report on Form 10-K for the fiscal year ended December 31, 2007. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. Certain amounts have been reclassified to conform to the current period consolidated financial statement presentation; such reclassifications had no effect on the period presented.

Use of Estimates in the Preparation of Financial Statements

        The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)

Cash and Cash Equivalents

        Cash and cash equivalents consist of all highly liquid investments that are readily convertible to cash and have maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

Prepaid Expenses and Other

        Included in prepaid expenses and other are deposits made on orders of pipe required for the Company's upcoming drilling program. As of June 30, 2008 there was approximately $2.0 million of deposits made and recorded. As of June 30, 2007, there were not deposits made or recorded.

Restricted Investment

        The restricted investment balance as of June 30, 2008, is comprised of: (a) $191,886 certificate of deposit to collateralize a surety bond to provide for state bonding requirements for plugging and abandonment liabilities; and (b) $52,348 certificate of deposit to collateralize the costs of office improvements that will be released over the four year remaining term of the lease at $17,450 per year.

Concentration of Credit Risk

        The Company's cash equivalents and short-term investments are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company may at times have balances in excess of the federally insured limits.

        The Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.

Oil and Gas Producing Activities

        The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to theses costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full costs pool.

        Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)

reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. During 2008 and 2007 approximately $0 and $499,500 respectively, of unproved land costs was reclassified to proved property and was included in the ceiling test and depletion calculations.

        Estimated reserve quantities and future net cash flows have the most significant impact on the Company because these reserve estimates are used in providing a measure of the Company's overall value. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company's proved properties.

        Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the Securities and Exchange Commission (the "SEC"), such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.

        The optimal method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Most of the Company's wells have been producing for a period of less than six years and for some, less than a year. Because of this short production history, other generally less accurate methods such as volumetric analysis and analogy to the production history of wells of ours and other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Company's estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Company's wells are produced over time and more data is available, the estimated proved reserves will be re-determined at least on a quarterly basis and may be adjusted based on that data.

        For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. 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. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues is computed by applying current prices of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions.

        Primarily as the result of the Company's inability to establish production and qualified reserves in its deep Vermillion Basin project, low natural gas prices in Wyoming, and the impairment of certain undeveloped properties in Wyoming and North Dakota, the Company recorded an impairment expense

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)

of $34.0 million in 2007 including $14.0 million in the first six months of 2007. No such impairments were recognized during the six months ended June 30, 2008.

Wells in Progress

        Wells in progress at December 31, 2007, represent the costs associated with wells that have not reached total depth or been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test. The costs for these wells is then transferred to proved property when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods.

Impairment of Long-lived Assets

        The Company's unproved properties are evaluated quarterly for the possibility of potential impairment. In the six months ended June 30, 2007 the Company reclassified approximately $499,500 of unproved property costs to the full cost pool. The Company recorded an impairment expense of $34.0 million in 2007, including $14.0 million in the first six months of 2007. In the six months ended June 30, 2008, the Company did not recognize any impairment losses.

Other Property and Equipment

        Other property and equipment such as office furniture and equipment, vehicles, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is recorded using the straight-line method over the estimated useful lives of three years for computer equipment, and five years for office equipment and vehicles. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Fair Value of Financial Instruments

        The Company's financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments.

Revenue Recognition

        The Company records revenues from the sales of natural gas and crude oil when they are produced and sold. The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners' gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company's over and under produced gas balancing positions are considered in the Company's proved oil and gas revenues. Gas imbalances at June 30, 2008, and December 31, 2007 were not significant.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)

Asset Retirement Obligation

        The Company follows SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the condensed consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are also included in the ceiling test calculation. The asset retirement liability will be allocated to operating expense by using a systematic and rational method. As of June 30, 2008, and December 31, 2007, the Company has recorded a net asset of $573,192 and $660,986 and a related liability of $757,324 and $874,498, respectively. In December 2007, the Company revised its estimated dismantlement and abandonment costs based upon the actual costs of recently plugged and abandoned wells. The information below reconciles the value of the asset retirement obligation for the periods presented.

Off Balance Sheet Arrangements

        The Company does not have any off-balance sheet financing arrangements at June 30, 2008.

Recently Adopted Accounting Pronouncements

        In September 2006, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 157, "Fair Value Measurements." The statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. In February 2008, the FASB issued Staff Position No. FAS 157-2 which proposed a one year deferral for the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually).

        On January 1, 2008 we elected to implement this Statement with the one-year deferral. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations or cash flows. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)

recurring basis. We are in the process of evaluating this standard with respect to our effect on nonfinancial assets and liabilities and have not yet determined the impact that it will have on our financial statements upon full adoption in 2009.

        In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities-Including an Amendment of FASB Statement No. 115" ("FAS 159"). This Statement allows an entity the option to elect fair value for the initial and subsequent measurement for certain financial instruments and other items that are not currently required to be measured at fair value. If a company chooses to record eligible items at fair value, the company must report unrealized gains and losses on those items in earnings at each subsequent reporting date. FAS 159 also prescribes presentation and disclosure requirements for assets and liabilities that are measured at fair value pursuant to this standard. FAS 159 was effective for the Company as of January 1, 2008. The adoption of FAS 159 did not have a material impact on the Company's financial position or results of operations.

Recently Issued Accounting Pronouncements

        In December 2007, the FASB issued SFAS No. 141-R, "Business Combinations" ("FAS 141R") which revised SFAS No. 141, "Business Combinations" ("FAS 141"). This pronouncement is effective for the Company's financial statements issued after January 1, 2009. Under FAS 141, organizations utilized the announcement date as the measurement date for the purchase price of the acquired entity. FAS 141R requires measurement at the date the acquirer obtains control of the acquiree, generally referred to as the acquisition date. FAS 141R will have a significant impact on the accounting for transaction costs, restructuring costs as well as the initial recognition of contingent assets and liabilities assumed during a business combination. Under FAS 141R, adjustments to the acquired entity's deferred tax assets and uncertain tax position balances occurring outside the measurement period are recorded as a component of the income tax expense, rather than goodwill. As the provisions of FAS 141R are applied prospectively, the impact to the Company cannot be determined until the transactions occur.

        In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51" ("FAS 160"). This Statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. FAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. The Company does not expect that the adoption of FAS 160 will have a material effect on its financial position or results of operations.

        In March 2008, the FASB issued FAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities" ("FAS 161"). FAS 161 amends and expands the disclosure requirements of FAS 133, "Accounting for Derivative Instruments and Hedging Activities" and requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This statement is effective for financial statements issued for fiscal periods beginning after November 15, 2008. Earlier adoption is not permitted. We do not believe the adoption of FAS 161 will have a material impact on our consolidated financial statements.

        In April 2008, the FASB issued FASB Staff Position ("FSP") FAS 142-3, "Determination of Useful Life of Intangible Assets" ("FSP FAS 142-3"). FSP FAS 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)

recognized intangible asset under FAS 142, "Goodwill and Other Intangible Assets." FSP FAS 142-3 also requires expanded disclosure related to the determination of intangible asset useful lives. FSP FAS 142-3 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not permitted. We do not believe the adoption of FAS FSP 142-3 will have a material impact on our consolidated financial statements.

Note 3—Wells in Progress

        The following table reflects the net changes in capitalized additions to wells in progress during the six months ended June 30, 2008, and the year ended December 31, 2007, and does not include amounts that were capitalized and reclassified to producing wells in the same period.

Note 4—Stock-based Compensation Plan

        In 2007 the Company adopted the 2007 Stock Incentive Plan (the "2007 Plan"), which replaced the Incentive Share Option Plan (the "Pre-existing Plan"). The 2007 Plan authorizes the Company to issue stock options, stock appreciation rights (SARs), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based awards to any employee, consultant, independent contractor, director or officer of the Company. A total of 8,000,000 shares of common stock may be issued under the 2007 Plan, which includes shares issuable under the Pre-existing Plan pursuant to options outstanding as of the effective date of the 2007 Plan. No more than 8,000,000 shares may be used for stock issued pursuant to incentive stock options and the number of shares available for granting restricted stock and restricted stock units shall not exceed 1,000,000, subject to adjustment as defined in the 2007 Plan. The Company granted 1,481,000 stock options at $2.87 per share and 1,465,000 stock options at $6.26 per share during the six-month period ended June 30, 2008 and 2007, respectively.

        Compensation expense charged against income for all stock-based awards during the six months ended June 30, 2008 and June 30, 2007, was $1,967,511 and $827,794, respectively. This increase is primarily due to additional stock-based awards granted since the adoption of the 2007 Plan, as well as the true-up of the cumulative expense as a result of comparing the assumed forfeiture rate to actual forfeitures.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4—Stock-based Compensation Plan (Continued)

        The following assumptions were used for the Black-Scholes model to calculate the stock-based compensation expense for the periods presented:

        The weighted average fair value at the date of grant for stock options granted is as follows:

        A summary of the stock options outstanding as of June 30, 2008, is as follows:

        At June 30, 2008, stock options outstanding were as follows:

        The aggregate intrinsic value of both outstanding and vested options as of June 30, 2008, was $10,219,903 based on the Company's June 30, 2008, closing common stock price of $4.56. The total grant date fair value of the shares vested during the six months ended June 30, 2008 was $1,559,446. As

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4—Stock-based Compensation Plan (Continued)

of June 30, 2008, there was $4,686,177 of total unrecognized compensation cost related to unamortized options. That cost is expected to be recognized over a period of approximately three years.

        As of June 30, 2008, there were 55,000 unvested shares of restricted stock grants with a weighted-average grant date fair value of $4.91 per share. Total unrecognized compensation cost of $196,187 related to non-vested restricted stock is expected to be recognized over a three-year 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 under an operating lease agreement that expires on June 30, 2012. Rent expense was $148,778 and $50,579 for the six month periods ended June 30, 2008 and 2007, respectively.

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

        During the second quarter of 2008, the Company entered into two-year contracts for the use of two new-build drilling rigs, with the first rig scheduled for delivery in September 2008 and the second one scheduled to follow in the first quarter of 2009. Each of the contracts provide for stand-by drilling rates of $18,000 per day. It is contemplated that these rigs will be mobilized to our acreage holdings on the Fort Berthold Indian Reservation, or FBIR. The drilling contracts for the two new-build rigs contain a provision allowing us to terminate the contract prior to delivery of the rigs or at any time during the two-year period in exchange for a payment equal to the stand-by drilling rate per day multiplied by 120 days, or $2,160,000 per contract.

        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 pay such commitments, the acreage positions or wells may be lost.

Note 6—Differences Between Canadian and United States Accounting Principles

        These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America 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. Management does not believe the 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 could 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

        This Quarterly Report includes certain statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, contained in this Quarterly Report, constitute forward-looking statements. In some cases you can identify forward-looking statements by terms such as "may," "intend," "might," "will," "should," "could," "would," "expect," "believe," "estimate," "anticipate," "plans," "predict," "project," "potential," or the negative of these terms, and similar expressions intended to identify forward-looking statements.

        Forward-looking statements are based on assumptions and estimates and are subject to risks and uncertainties. We have identified in this Quarterly Report some of the factors that may cause actual results to differ materially from those expressed or assumed in any of our forward-looking statements. There may be other factors not so identified. Factors that may cause actual results to differ materially from those expressed or implied by our forward-looking statements include, but are not limited to, the factors set forth, from time to time, by us in reports filed with the SEC, including those described under the heading "Risk Factors" in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2007 and the following:

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our future financial and operating performance;



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our business strategy;



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the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and producing oil and natural gas;



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market demand;



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drilling of wells;



•

risks and uncertainties involving geology of oil and natural gas deposits;



•

the uncertainty of reserves estimates and reserves life;



•

the uncertainty of estimates and projections relating to production, costs and expenses;



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potential delays or changes in plans with respect to exploration or development projects or capital expenditures;



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our dependence on key personnel;



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fluctuations in oil and natural gas prices, foreign currency exchange rates and interest rates;



•

health, safety and environmental risks;



•

uncertainties as to the availability and cost of financing;



•

unforeseen liabilities arising from litigation; and



•

the possibility that government policies or laws may change or governmental approvals may be delayed or withheld.

        Other sections of this Quarterly Report may include additional factors that could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time and it is not possible for our management to predict all risk factors, nor can we assess the impact of all factors on our business or

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the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

        Our forward-looking statements contained in this Quarterly Report are made as of the respective dates set forth in this Quarterly Report. Such forward-looking statements are based on the beliefs, expectations and opinions of management as of the date the statements are made. We do not intend to update these forward-looking statements, except as otherwise required by law. For the reasons set forth above, investors should not place undue reliance on forward-looking statements.

Overview

        Kodiak Oil & Gas Corp. is an independent energy company focused on the exploration, exploitation, acquisition and production of natural gas and crude oil in the United States. Our oil and natural gas reserves and operations are primarily concentrated in two Rocky Mountain basins—the Green River Basin of Wyoming and Colorado and the Williston Basin of North Dakota and Montana. 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 conventional and unconventional prospects, that we have the opportunity to explore, drill and develop.

        During the year we re-evaluated our exploration strategy in the Bakken shale play. Based, in part, on the announced drilling and production results of other operators in the immediate area of our Bakken shale acreage in the west central North Dakota counties of Mountrail, Dunn and McKenzie, we revised our capital expenditure budget. In our previously announced capital expenditure budget, we had anticipated selling down a portion of our acreage in order to fund a portion of our 2008 drilling program. As we continued to evaluate the Bakken play, we revised our strategy and intend to continue our acreage acquisition while maintaining a high working interest. Furthermore, due to the high level of drilling activity in the United States and our concern about the availability of drilling pipe, we have acquired or made deposits on projected pipe requirements for the first seven wells. As of June 30, 2008, we had prepaid $2 million towards the cost of this pipe. As a result of these developments and this change in strategy, our working capital at June 30, 2008 of $3.1 million will not be sufficient to meet the revised budgeted capital expenditures of $16.4 million during the balance of our 2008 fiscal year. We will need to obtain significant additional working capital through debt or equity financings or by entering into additional joint venture agreements. We cannot be certain that additional funding will be available on acceptable terms, or at all. If we are unable to raise additional capital when required or on acceptable terms, we may have to significantly delay, scale back or discontinue our drilling or exploration program, seek to enter into additional joint venture arrangements with third parties, or seek to sell one or more of our properties. A significant delay in obtaining additional financing would have a material adverse effect on our business.

Recent Developments

Oil and Gas Property Leasing and Permitting Activities

        In the second quarter of 2008, we continued to add to our acreage position in the Bakken play on the FBIR. We received final regulatory approval on a permit to drill our first well on the FBIR. We have completed building the drill site with an anticipated spud date of our Tall Bear #16-15H well in September 2008. Subsequent to June 30, 2008, we received final approval on two additional drill sites and we have several other permits in various stages.

        We participated in the acquisition of acreage in the Vermillion Basin in Wyoming in the second quarter of 2008, in accordance with our agreement with Devon Energy Production Company, L.P., a wholly owned subsidiary of Devon Energy Corp. ("Devon"), which we entered into earlier this year

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("Devon Agreement"). As a result of these acquisitions, we increased our acreage by 2,321 net acres in the Vermillion Basin. Drilling permits are being finalized to authorize the drilling of up to five wells, commencing in the third quarter of 2008.

Workover Activities

        During the second quarter, we finished completion and workover activities on three of our wells producing from the Bakken Formation in the Mon-Dak Field, located on the Montana—North Dakota state line. The completion work consisted of fracture stimulation work on the three wells. During this work we encountered mechanical problems on one of the wells, and it was necessary to repair the casing in the well. This well has been placed back on pump and we will evaluate whether additional completion work on the well will be performed in the future. Operationally, it is still too early to assess the results of completion on this well and the two other wells that were fracture stimulated. The lack of steady production from these wells during the first six months has had a significant impact on our oil and gas sales. We expect production from these wells to resume in last half of 2008.

Drilling Rig Contracts

        We have entered into two-year contracts for the use of two new-build drilling rigs, with the first rig scheduled for delivery in September 2008 and the second one scheduled to follow in the first quarter of 2009. Each of the contracts provide for stand-by drilling rates of $18,000. It is contemplated that these rigs will be mobilized to our acreage holdings on the FBIR. The drilling contracts, for the two new-build rigs contain a provision allowing us to terminate the contract prior to delivery of the rigs or at any time during the two year period in exchange for a payment equal to the stand-by drilling rate per day multiplied by 120 days, or $2,160,000.

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 about producer ability to ensure sufficient supply to meet increasing demand amid a host of uncertainties caused by political instability, a weaker 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 do not currently have hedges of our commodity sales 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 six-month periods ended June 30, 2008, and June 30, 2007.

        During the first six months of 2008, we performed workover and completion activities on our producing Bakken oil wells in McKenzie County, North Dakota. Although this work is expected to improve the production capabilities of these wells and increase their recoverable reserves, while the project was in progress, the wells' production was negatively impacted. As part of this work, we performed repairs on the casing of one well and that well and two other wells were shut in intermittently during the first half of 2008. As a result, our oil production for the three and six month periods ended June 30, 2008 decreased significantly and the expenses that were incurred for repair

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work increased operating expenses by approximately $1.4 million. The sales volume and production cost data shown below reflect the effect of the reduced production and increased expenses.

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Results of Operations

For the Three Months Ended June 30, 2008 compared to the Three Months Ended June 30, 2007

        The Company reported a net loss for the three months ended June 30, 2008 of $1,898,441, compared with a net loss of $449,246 for the same period in 2007. The Company's net loss for the three months ended June 30, 2008 was impacted by the reduced crude oil production and increased operating expenses as a result of workover and repair procedures on its producing Bakken oil wells in McKenzie County, North Dakota (approximately $1.0 million).

Oil and Gas Revenue and Production

        Natural gas production volumes decreased 31% and oil production volumes decreased 52% for the three month periods ended June 30, 2008, compared to the same period in 2007. Oil and natural gas production decreased due to workover operations on producing wells. Total gas price realizations increased 197% to $12.80 per Mcf for the three month period ended June 30, 2008, compared to $4.29 per Mcf for the same period in 2007. Oil price realizations were $115.42 per barrel for the three month period ended June 30, 2008, compared to $61.21 for the same period in 2007. The net effect of the pricing and volume changes resulted in an increase of oil and gas revenues of $94,204 to $1,963,806 for the three month periods ended June 30, 2008, compared to the same period in 2007.

Lease Operating Expenses

        The Company recorded workover, lease operating and production tax expense of $1,282,618 during the three month period ended June 30, 2008, as compared to $345,998 during the same period in 2007. In the second quarter of 2008, we completed workover operations on our producing Bakken oil wells in McKenzie County near the North Dakota and Montana state line. As part of this program we performed repair work on the casing of one well. This work was completed and the well is back on production. The net cost of approximately $1.0 million related to the repair work was charged to oil and gas production costs and expenses in the second quarter of 2008 in addition to approximately $0.4 million accrued in the first quarter of 2008.

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Depletion, Depreciation and Amortization

        Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was $786,777 for the three month period ended June 30, 2008, compared to $986,767 for the same period in 2007. DD&A expense decreased during the quarter due to the reclassification of wells whose costs were previously classified as wells in progress thus increasing the amortization pool and the DD&A rate. This increase was partially offset by the reduced crude oil volume produced due to the workover operations on producing oil wells.

Impairment

        There were no impairment charges for the three month periods ended June 30, 2008 and 2007.

General and Administrative Expense

        The Company's general and administrative costs of $1,831,508 during the three months ended June 30, 2008, compares to $2,026,443 for the same period in 2007. Included in the general and administrative expense for this period is a stock-based compensation charge of $448,701 and $552,214 for 2008 and 2007, respectively, for options and restricted stock issued to officers, directors and employees. The decrease in stock compensation expense is primarily due to the decrease in Kodiak's share price used for valuation at the time of grant in 2007 to 2008. The overall decrease is also due to this lower stock compensation expense during the quarter.

EBITDA

        In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gain on foreign currency, stock-based compensation expense and accretion of abandonment liability ("Adjusted EBITDA") as a key indicator of financial operating performance and as a measure of the ability to generate cash for operational activities and future capital expenditures. The Company's Adjusted EBITDA decreased $1,168,638 to a loss of $664,735 for the three months ended June 30, 2008 from the same period in 2007. The decrease in Adjusted EBITDA was largely the result of decreased oil production as a result of workovers and repair work on producing wells. The repair costs increased operating expenses in the second quarter of 2008 and reduced Adjusted EBITDA by approximately $1.0 million. Adjusted EBITDA is not a Generally Accepted Accounting Principle ("GAAP") measure of performance. The Company uses this non-GAAP measure primarily to compare its performance with other companies in the industry that make a similar disclosure and as a measure of its current liquidity. The Company believes that this measure may also be useful to investors for the same purpose and for an indication of the Company's ability to generate cash flow at a level that can sustain or support our operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for operating income or loss, cash flow from operations determined under GAAP, or any other measure for determining the Company's operating performance that is calculated in accordance with GAAP. In addition, because EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies.

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Reconciliation between EBITDA and net income for the three months ended June 30, 2008 and 2007 is provided in the table below:

Results of Operations

For the Six Months Ended June 30, 2008 compared to the Six Months Ended June 30, 2007

        The Company reported a net loss for the six months ended June 30, 2008, of $4,530,477 compared with a net loss of $14,904,079 for the same period in 2007. The Company's net loss for the six months ended June 30, 2008, was impacted by the reduced crude oil production and increased operating expenses as a result of workover and repair procedures on its producing Bakken oil wells in McKenzie County, North Dakota (approximately $1.4 million).

Oil and Gas Revenue and Production

        Natural gas production volumes increased 5% and oil production volumes decreased 45% for the six month periods ended June 30, 2008, compared to the same period in 2007. Natural gas production remained steady as compared to the six month period ended June 30, 2007. Oil production decreased due to workover operations on producing wells. Total gas price realizations increased 69% to $9.04 per Mcf for the six month period ended June 30, 2008, compared to $5.32 per Mcf for the same period in 2007. Oil price realizations were $100.97 per barrel for the six month period ended June 30, 2008, compared to $56.04 for the same period in 2007. The net effect of the pricing and volume changes resulted in an increase of oil and gas revenues of $395,558 to $3,841,977 for the six months ended June 30, 2008, compared to the same period in 2007.

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Lease Operating Expenses

        The Company recorded workover, lease operating and production tax expense of $2,265,569 during the six months ended June 30, 2008, as compared to $736,773 during the same period in 2007. In the second quarter of 2008, we completed workover operations on our producing Bakken oil wells in McKenzie County near the North Dakota and Montana state line. As part of this program, we performed repair work on the casing of one well. This work was completed and the well is back on production. The net cost of approximately $1.4 million related to the repair work was charged to oil and gas production costs and expenses in the first half of 2008.

Depletion, Depreciation and Amortization

        Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was $1,884,076 for the six month period ended June 30, 2008, compared to $2,026,013 for the same period in 2007. DD&A expense decreased during the period due to the reclassification of wells whose costs were previously classified as wells in progress thus increasing the amortization pool and the DD&A rate. This increase was partially offset by the reduced crude oil volume produced due to the workover operations on producing oil wells.

Impairment

        There were no impairment charges for the six months ended June 30, 2008. Asset impairment of $14,000,000 was charged during the six months ended June 30, 2007.

General and Administrative Expense

        The Company's general and administrative costs were $4,326,551 during the six months ended June 30, 2008, compared to $3,289,403 for the same period in 2007. Included in the general and administrative expense for this period is a stock-based compensation charge of $1,967,511 and $827,794 for 2008 and 2007, respectively, for options and restricted stock issued to officers, directors and employees. The increase to the stock-based compensation charge is the result of options and restricted stock granted subsequent to June 30, 2007, and the true-up of stock-based compensation expense for the difference between actual forfeitures and assumed forfeitures when the awards were granted. The overall increase in general and administrative expenses is due in part to the Company's increased staffing requirements and level of activity. The Company currently has eighteen full time and three contract employees compared to fifteen full time and one part time employee in June 2007.

EBITDA

        In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gain on foreign currency and stock-based compensation ("Adjusted EBITDA") as a key indicator of financial operating performance and as a measure of the ability to generate cash for operational activities and future capital expenditures. The Company's Adjusted EBITDA decreased $1,928,657 to a loss of $662,382 for the six months ended June 30, 2008 from the same period in 2007. The decrease in Adjusted EBITDA was largely the result of decreased oil production as a result of workovers and repair work on producing wells. The repair costs increased operating expenses in the first half of 2008 and reduced Adjusted EBITDA by approximately $1.4 million. Adjusted EBITDA is not a Generally Accepted Accounting Principle ("GAAP") measure of performance. The Company uses this non-GAAP measure primarily to compare its performance with other companies in the industry that make a similar disclosure and as a measure of its current liquidity. The Company believes that this measure may also be useful to investors for the same purpose and for an indication of the Company's ability to generate cash flow at a level that can sustain or support our operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for operating income or loss, cash flow from operations determined under GAAP, or any other measure

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for determining the Company's operating performance that is calculated in accordance with GAAP. In addition, because EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies. Reconciliation between EBITDA and net income for the six months ended June 30, 2008 and 2007 is provided in the table below:

Liquidity and Capital Resources

        Kodiak ended the second quarter of 2008 with cash and cash equivalents of $1.2 million down from $13.0 million at year-end 2007. Total working capital was $3.1 million at June 30, 2008, as compared to $10.2 million at December 31, 2007. Cash flow used in operating activities for the first half of 2008 was $5.2 million which was largely the result of a $1.4 million workover expenditure and a $2.0 million deposit placed on drilling pipe for seven wells. Cash used as capital expenditures for our oil and gas activities totalled $9.2 million for the first half of 2008 and was offset by $2.4 million in proceeds from sales of oil and gas properties.

        Kodiak's 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 first half of 2008, our oil and gas revenue increased by 11% from $3.4 million during the first half of 2007 to $3.8 million. This increase is largely the result of the increased prices received for both our crude oil and natural gas production partially offset by the decrease in our crude oil production as a result of oil producing wells that were shut in for completion, repair and workover procedures. Total costs and expenses decreased to $8.5 million in the first half of 2008 from $19.4 million in the first half of 2007 largely due to an asset impairment in 2007 of $14.0 million related to the full cost ceiling test in 2007. The increase in general and administrative expenses included an increase in the non-cash charge for stock based compensation of $1.3 million from the first half of 2007 to the first half of 2008. This increase is due to additional options and restricted stock issued since implementing the 2007 Plan, and a change in the forfeiture rate assumed for future vested options.

        Due to our active oil and natural gas exploration program, we have experienced, and expect to continue to experience, substantial working capital requirements. As a result of our agreement with

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Devon, we expect to maintain a high level of activity in the Vermillion Basin, without the need for Kodiak to undertake significant capital expenditures in the short-term. Based on our current exploration program and depending on the success in this play, we anticipate additional capital requirements during the second half of 2008 and into 2009. By reducing the immediate capital requirements of our Vermillion Basin exploration, we intend to allocate our existing capital to the Bakken play on the Fort Berthold Indian Reservation in North Dakota. Through an exploration agreement with two joint venture partners in this play, we have limited our initial capital exposure to an approximate 50% to 70% working interest in the initial 14 wells.

        In the first half of 2008, we incurred capital expenditures of approximately $6.8 million, net of proceeds from property divestitures and our agreement with Devon. As of June 30, 2008, our working capital was $3.1 million and we had no long-term debt. Our capital expenditure budget for 2008 has been increased from $12.6 million to $22.7 million. Our budgeted capital expenditures are net of proceeds from limited divestitures and joint venture arrangements that have occurred or are planned. In addition to the planned expenditures in our $22.7 million revised budget, we have other prospects that are in the early stages of exploration. Further spending on these prospects is contingent on the success of the currently budgeted expenditures. As our anticipated funds from operations are expected to provide only a limited amount of additional working capital, we believe that we will need to obtain additional sources of capital to fund further growth and development, the amount and timing of which will depend on the success and timing of our exploration activities. We anticipate that we would seek to obtain additional funding either by means of debt or equity financings or by entering into additional joint venture agreements, the availability of which there can be no assurance. The Company is currently negotiating a secured line of credit with a bank and believes that the line of credit will be completed in the third quarter of 2008. On July 14, 2008, the Company filed a registration statement on Form S-3 to register for sale from time to time up to $150 million of common stock or debt securities. The registration statement was declared effective on July 24, 2008.

        Our ability to fund our operations in future periods will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot be certain that additional funding will be available on acceptable terms, or at all. If we are unable to raise additional capital when required or on acceptable terms, we may have to significantly delay, scale back or discontinue our drilling or exploration program, seek to enter into additional joint venture arrangements with third parties, or seek to sell one or more of our properties. A significant delay in obtaining additional financing would have a material adverse effect on our business.

Oil and Gas Properties

        As of June 30, 2008, we had several hundred lease agreements representing approximately 169,200 gross and 101,400 net acres, primarily in the Green River and Williston Basins.

        As of June 30, 2008, we had acquired approximately 53,700 gross acres and 37,700 net acres in the Bakken oil play in Dunn County, North Dakota. 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 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. We have not yet conducted any drilling operations in our Bakken oil play in the FBIR, but plan to commence our first well in the second half of 2008. Subject to the necessary financing, we expect to continue drilling in the FBIR thereafter, utilizing two rigs commencing in the first quarter of 2009.

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        Our leasehold interests in the Vermillion Basin total approximately 43,200 gross and 16,200 net acres. The area of mutual interest ("AMI") with Devon will expire on January 1, 2013, unless extended by mutual agreement of both parties. Each party has agreed to an equal share of any interest or lease acquired within the participating area. We have not yet completed any drilling under the Devon Agreement, but expect that Devon will commence drilling operations in the second half of 2008.

        In January 2008, we completed the sale of 4,144 gross and net acres in an exploratory Mancos Shale gas prospect located in the Sand Wash Basin in Moffat County, Colorado for $1.2 million. We retained a 5% overriding royalty in these properties as well as 100% working interest ownership in the remaining 3,770 acres. We believe the remaining acreage is prospective for production from the Mancos Shale and Niobrara Formation at a shallower depth than that divested.

        The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of June 30, 2008.

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(1)

Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves.

(2)

Developed acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production.

(3)

Excludes 10,261 gross (6,127 net) acres that can be earned pursuant to existing farm-in agreements.

Exploratory Activity

Operations in the Williston Basin of Montana and North Dakota

Bakken Formation—McKenzie and Dunn Counties, North Dakota

        We have continued our ongoing acreage acquisition program in Dunn County, North Dakota where the primary objective is the dolomitic, sandy interval layered between the two Bakken shales at an approximate vertical depth of 10,000 feet. All of Kodiak's leaseholds are on the Fort Berthold Indian Reservation. At June 30, 2008, Kodiak had approximately 53,700 gross and 37,700 net acres under lease. Kodiak operates all of its leasehold on the Reservation excepting an approximate 7,000 net acres that are in a participating area previously established with another operator. Kodiak continues to add to its leasehold position in core Dunn County operating areas where deemed appropriate.

        Construction of the drill site for Kodiak's initial Bakken well on the FBIR, the Tall Bear #16-15H well, has been completed. The Tall Bear #16-15H is a horizontal well targeting oil potential in the middle Bakken and has been permitted to a proposed total depth of 15,600 feet. We will operate and own 68.75% working interest in the proposed drill site and acreage block. The Company has entered

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into a contractual agreement for a new-build drilling rig which is scheduled for September 2008 delivery. In anticipation of its 2008 Bakken drilling program, Kodiak recently purchased drilling pipe for seven horizontal Bakken wells along with four complete production facilities. Delivery of this equipment is expected in the third quarter of 2008. The Company also signed a contract for a second new-build rig to be delivered late in the first quarter of 2009.

        Kodiak's exploration team is working with regulatory agencies in an effort to assemble the required drilling permits to allow both drilling rigs to operate continuously. The Company recently received governmental approval on two additional drilling permits. Surveying and the scoping period has been completed on two additional drill pads, with Environmental Assessments (EA) to follow. In an effort to minimize surface disturbance and to eliminate certain construction costs, each drill pad will provide two well sites for wells to be drilled in the opposite direction.

        During the first half of 2008, Kodiak completed a three-well recompletion and workover program in an effort to improve production on three Bakken producers located in the Mon-Dak Field in McKenzie County, North Dakota. Sufficient data is not yet available to determine the effect of the recompletion program. Initial fracture stimulation operations were completed on the Grizzly Federal #4-11, originally completed in 2007. The well is currently flowing back frac fluid. The Grizzly #13-6 underwent re-frac operations and is also being flowed back. The Grizzly Federal #1-27 had damaged casing which required significant repair work. The well has been placed back on production and we will evaluate whether additional completion work on the well will be performed in the future. The net cost of approximately $1.4 million related to the repair work was charged to oil and gas production costs and expenses in the first half of 2008.

Red River-Mission Canyon Play—Sheridan County, Montana and Divide County, North Dakota

        The primary producing objectives in this prospect area are the Mission Canyon and the Red River formations at approximate depths of 8,000 feet and 11,000 feet, respectively. We have recently completed interpreting an approximate 18 square mile 3-D seismic program over a portion of this acreage. Kodiak is preparing to drill two wells, in which it has a 37.5% working interest and will operate, that will test the productive potential of the Red River Formation. Drilling is scheduled to commence in the second half of 2008 depending upon rig availability, which we are unable to predict.

Operations in the Green River Basin of Wyoming and Colorado

Vermillion Basin Deep—Baxter Shale and Frontier and Dakota Sandstone

        Our primary leaseholdings in the Green River Basin are located in an area referred to as the Vermillion Basin. In this geologic region, we believe there is natural gas trapped in various sands, coals and shales at depths ranging to nearly 15,000 feet. The primary target of our current exploration efforts in this area is the over-pressured Baxter Shale at depths to approximately 12,500 feet. Kodiak currently has approximately 43,200 gross and 16,200 net acres under lease and can earn additional interest through existing farm-in agreements.

Horseshoe Basin Unit

        In January 2008, we entered into the Devon Agreement under which Devon earned an interest in our leasehold interests in the Vermillion Basin in exchange for, among other things, drilling up to three wells, or after incurring total costs approximating the costs of three drilled and completed wells, at Devon's sole cost and risk. Upon completion of these capital expenditures, we will have a 50% working interest in all of the wells, proportionately reduced in the event of third-party interest. By incurring these capital expenditures, Devon will have fulfilled its commitment and will have earned, among other considerations, 50% of our leasehold interest to all depths within the AMI, excluding any leasehold already jointly held by and between us and Devon and any existing Kodiak wellbores.

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        Under the Devon Agreement, the companies plan to drill two vertical wells and one horizontal well employing redesigned drilling and completion techniques in an effort to minimize reservoir damage and improve production rates. These wells, together with the HB #5-3 well drilled and completed by Kodiak in late 2007, will help the Company understand the size of this play. The Horseshoe Basin Unit comprises approximately 8,200 Kodiak gross acres and 2,500 net acres. Additionally, Devon and Kodiak can each earn an interest under approximately 6,000 gross and 3,000 net acres by further drilling.

        We expect construction of nine miles of pipeline to connect the HB #5-3 well to sales to commence during the second half of 2008 with completion scheduled for fourth quarter. There have been some delays in the well connection while we attempt to optimize midstream infrastructure in the Horseshoe Basin Unit for this well and additional wells expected to be drilled in the Unit.

Coyote Flats Federal Unit

        On the northern portion of Kodiak's leasehold, in the recently created Coyote Flats Federal Unit, Devon and Kodiak are planning to drill one vertical well and one horizontal well. The horizontal well will directly offset the State Federal #4-36 well drilled by Kodiak in 2006. The State Federal #4-36 had significant gas shows during drilling and the initial completion stages. However, during the completion work the well encountered significant mechanical problems and the deeper zones were abandoned as casing collapsed and only the upper zones are producing. Coyote Flats Federal Unit comprises approximately 28,500 Kodiak gross acres and 11,900 net acres.

Capital Expenditures

        Our revised budgeted net capital expenditures are expected to be $22.7 million in 2008. The following table sets forth our capital expenditures for the six months ended June 30, 2008 and our planned capital expenditures for our principal properties in 2008. Net capital expenditures include both cash and accrued expenditures and are net of proceeds from divestitures. The 2008 estimated expenditures do not include the costs to drill additional wells that could help further evaluate our properties in the Vermillion Basin. These wells are to be drilled at the sole cost of Devon under the Devon Agreement, with such drilling expected to commence in the third quarter of 2008.

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(1)

Net Capital Expenditures include accruals and are net of proceeds from divestitures.

        As is described elsewhere, we do not currently have sufficient working capital to complete our capital expenditure program and to provide for our continuing negative cash flow from operating

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activities. In order to complete our capital budget, we will be dependent on additional debt or equity financing, which may not be available on acceptable terms, if at all.

Off-Balance Sheet Arrangements

        We do not have any off-balance sheet financing arrangements at June 30, 2008.

Critical Accounting Policies and Estimates

        We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2007.

Recently Issued Accounting Pronouncements

        In December 2007, the FASB issued SFAS No. 141-R, "Business Combinations" ("FAS 141R") which revised SFAS No. 141, "Business Combinations" ("FAS 141"). This pronouncement is effective for the Company's financial statements issued after January 1, 2009. Under FAS 141, organizations utilized the announcement date as the measurement date for the purchase price of the acquired entity. FAS 141R requires measurement at the date the acquirer obtains control of the acquiree, generally referred to as the acquisition date. FAS 141R will have a significant impact on the accounting for transaction costs, restructuring costs as well as the initial recognition of contingent assets and liabilities assumed during a business combination. Under FAS 141R, adjustments to the acquired entity's deferred tax assets and uncertain tax position balances occurring outside the measurement period are recorded as a component of the income tax expense, rather than goodwill. As the provisions of FAS 141R are applied prospectively, the impact to us cannot be determined until the transactions occur.

        In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51" ("FAS 160"). This Statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. FAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. We do not expect that the adoption of FAS 160 will have a material effect on our financial position or results of operations.

        In March 2008, the FASB issued FAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities" ("FAS 161"). FAS 161 amends and expands the disclosure requirements of FAS 133, "Accounting for Derivative Instruments and Hedging Activities" and requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This statement is effective for financial statements issued for fiscal periods beginning after November 15, 2008. Earlier adoption is not permitted. We do not believe the adoption of FAS 161 will have a material impact on our consolidated financial statements.

        In April 2008, the FASB issued FASB Staff Position ("FSP") FAS 142-3, "Determination of Useful Life of Intangible Assets" ("FSP FAS 142-3"). FSP FAS 142-3 amends the factors that should be considered in developing the renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FAS 142, "Goodwill and Other Intangible Assets." FSP FAS 142-3 also requires expanded disclosure related to the determination of intangible asset useful lives. FSP FAS 142-3 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not permitted. We do not believe the adoption of FAS FSP 142-3 will have a material impact on our consolidated financial statements.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and Gas Price Fluctuations

        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 will result in approximately a $85,500 change in our gross gas production revenue. A $1.00 per barrel change in the market price of oil will result in approximately a $28,700 change in our gross oil production revenue. The impact on any potential sale of property cannot be readily determined.

Interest Rate Fluctuations

        We currently maintain some 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 US dollar interest rates. A 1% change in the interest rate would have approximately a $54,200 annual impact if all of our cash, as of June 30, 2008, was invested in interest bearing notes.

ITEM 4.    CONTROLS AND PROCEDURES

        Under the supervision and with the participation of our management, we evaluated the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the "Exchange Act") as of June 30, 2008. On the basis of this review, our management concluded that our disclosure controls and procedures are effectively designed to give reasonable assurance that the information we are required to disclose in reports that we file 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. Additionally, our CEO and CFO have concluded, as of June 30, 2008, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

        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

        None.

ITEM 1A.    RISK FACTORS

        Other than the following update, there have been no material changes to the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2007, as filed with the SEC on March 14, 2008. The risk factors disclosed here and in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, in addition to the other information set forth in this quarterly report, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

        The risk factor update is as follows:

Risks Related to the Company

We have a recent history of negative reserve revisions.

        We have a recent history of negative reserve revisions that occurred during the last two fiscal years. Specifically, our December 31, 2007 natural gas reserves reflected a downward revision of the December 31, 2006 reserves in the amount of 1.1 BCF, primarily as a result of the revision of reserves associated with the underperformance of one Vermillion Basin exploratory well. Our December 31, 2006 natural gas reserves reflected a downward revision of the December 31, 2005 reserves of 2.8 BCF, primarily as a result of the revision of reserves associated with our decision to discontinue exploration and development of our coalbed methane properties. Due to the imprecise nature of estimating natural gas and oil reserves as well as the potential volatility in natural gas and oil prices and their effect on the carrying value of our natural gas and oil properties, negative reserve revisions in the future may also be required as a result of factors that may negatively affect the present value of proved natural gas and oil reserves. These factors can include volatile natural gas and oil prices, downward revisions in estimated proved natural gas and oil reserve quantities, limited classification of proved reserves associated with successful wells and unsuccessful drilling activities. When reserves are found to be materially lower than we had estimated and reported, our prospects and stock price could be adversely affected.

Risks Related 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, which was declared effective by the SEC on July 24, 2008. Under this shelf registration statement, we may seek to raise 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.

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

        None.

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ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

        None.

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        The Company held its Annual General Meeting of Shareholders on May 22, 2008. The meeting was held to elect five directors to serve until the 2009 Annual General Meeting of Shareholders, to ratify the selection of Hein & Associates LLP as independent auditors of the Company for the year ending December 31, 2008 and to ratify certain amendments to the bylaw of the Company.

        The results of the voting related to the elections of the nominees for director are below. The "For" column represents the number of affirmative votes, and the "Withheld" column represents the number of abstentions and broker non-votes by holders of common stock represented by either proxy or in person at the meeting.

        Shareholders voted 68,178,194 shares for the proposal to ratify the selection of Hein & Associates LLP as independent auditors of the Company for the fiscal year ending December 31, 2007, with 274,347 shares withheld.

        Shareholders voted 61,292,518 shares for the ratification of amendments to the bylaw of the Company made effective March 25, 2008 to clarify that common shares of the Company may be issued and transferred electronically without a physical certificate, with 7,124,376 shares voted against.

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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