A summary of the stock options outstanding as of January 1, 2011 and March 31, 2011 is as follows:

At March 31, 2011, stock options outstanding were as follows:

        The aggregate intrinsic value of both outstanding and vested options as of March 31, 2011 was $20.0 million based on the Company's March 31, 2011 closing common stock price of $6.70 per share. The total grant date fair value of the shares vested during the three months ended March 31, 2011 was $2.9 million. As of March 31, 2011, there was $5.0 million 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 March 31, 2011, there were 310,500 unvested shares of restricted stock and restricted stock units with a weighted average grant date fair value of $6.52 per share.

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4—Share-Based Payments (Continued)

        In the first quarter of 2011, the Company awarded tandem grants of 105,000 restricted stock units ("RSUs") and 52,500 performance awards ("PAs") to employees pursuant to the Company's 2007 Plan. Subject to the satisfaction of certain performance-based conditions, the RSUs and PAs vest one-quarter per year over a four year service date and the Company began recognizing compensation expense related to these grants beginning in 2011 over the vesting period. In March 2011, the Company awarded tandem grants of 22,500 RSUs and 11,250 PAs to its Board of Directors pursuant to the Company's 2007 Plan. The RSUs and PAs vest after a one year service date and the Company will recognize compensation expense related to these grant beginning in 2011 over the vesting period. Total unrecognized compensation cost of $1.8 million related to non-vested restricted stock and RSUs is expected to be recognized over a four year period. The Company recognizes compensation cost for performance based grants on a tranche level and service-based grants on a straight-line basis over the requisite service period for the entire award. The fair value of restricted stock and RSU 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 space in Denver, Colorado and Dickinson, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on April 30, 2016. The Dickinson, North Dakota lease expires December 31, 2013. Rent expense for the quarter ended March 31, 2011 was $87,000 and $289,000 for the year ended in 2010. The Company has no other material capital leases and no other operating lease commitments.

        The following table shows the annual rentals per year for the life of the combined office leases:

        As of March 31, 2011 the Company was subject to commitments on three drilling rig contracts. One of the contracts expires in late 2011, one in 2012 and the third in 2013. Subsequent to March 31, 2011, we executed a fourth rig with a two-year drilling obligation. Rig delivery and the effective date of the contract governing the rig is expected to be May 15, 2011. In the event of early termination under all of these contracts, the Company would be obligated to pay an aggregate amount of approximately $41.4 million as of May 5, 2011 as required under the varying terms of such contracts.

        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.

        The Company may issue debt securities in the future that the Company's wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., may guarantee. Any such guarantee is expected to be full, unconditional and joint and several. The Company has no independent assets or operations nor does it have any

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5—Commitments and Contingencies (Continued)

other subsidiaries. There are no significant restrictions on the ability of the Company to receive funds from the Company's subsidiary through dividends, loans, advances or otherwise.

Note 6—Credit Facility

First Lien Credit Agreement

        On April 13, 2011, Kodiak Oil & Gas (USA) Inc. (the "Borrower"), a wholly owned subsidiary of Kodiak Oil & Gas Corp., entered into the Second Amendment (the "Second Amendment") to Credit Agreement with Wells Fargo Bank, N.A. ("Wells Fargo"), which amends that certain Credit Agreement (the "Credit Agreement") between the Borrower and Wells Fargo, dated May 24, 2010, as amended by the First Amendment to Credit Agreement, dated November 30, 2010 (the "Credit Agreement").

        The Second Amendment amends the Credit Agreement to, among other things, (i) increase the borrowing base from $50,000,000 to $75,000,000; (ii) decrease the borrowing base increase fee from 1.0% to 0.5%; (iii) reduce the commitment fee from a flat fee of 0.50% to a sliding scale of .375% to 0.50%, depending on borrowing base usage; and (iv) decrease the interest rate through a reduction in the applicable margin applied to the alternate base or adjusted LIBO interest rates (each as defined in the Credit Agreement) payable on outstanding borrowings. The applicable margin was reduced on the alternate base rate from a sliding scale of 1.25% to 2.25% to a sliding scale of 0.75% to 1.75%, depending on borrowing base usage. The applicable margin was reduced on the adjusted LIBO rate from a sliding scale of 2.25% to 3.25% to 1.75% to 2.75%, depending on borrowing base usage.

        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 (including unused borrowing capacity) to consolidated current liabilities not less than 1.0:1.0 and a ratio of total debt to EBITDAX (as defined in the Credit Agreement) to 4.0 to 1.0 for the four fiscal quarters ending on the last day of any fiscal quarter ending on or before December 31, 2010 and to 3.75 to 1.0 for the four fiscal quarters ending on the last day of each fiscal quarter thereafter; (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; (e) requires the Company to maintain a ratio of EBITDAX to Interest Expense (each as defined in the Credit Agreement) of at least 3.0 to 1.0 for the four fiscal

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6—Credit Facility (Continued)

quarters ending on the last day of any fiscal quarter and (f) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. As of March 31, 2011, the Company was in compliance with all covenants under the credit agreement. There were no borrowings under the First Lien Credit Agreement at March 31, 2011, or as of the date of this filing.

Second Lien Credit Agreement

        On November 30, 2010, Kodiak Oil & Gas (USA) Inc. entered into a second lien term loan credit agreement with an initial commitment of $40 million (the "Second Lien Credit Agreement") with Wells Fargo Energy Capital, Inc. and any other lender party thereto from time to time (collectively, the "Lenders"). As of March 31, 2011 and December 31, 2010, the entire $40 million commitment was outstanding. Subsequent to March 31, 2011, no borrowings or repayments have occurred under the Second Lien Credit Agreement.

        Interest on the loans under the Second Lien Credit Agreement will accrue based on one of the following two fluctuating reference rates in a manner prescribed under the applicable loan documents: (1) the LIBOR rate (which is primarily based on the London interbank market rate), subject to a floor of 2.5% and (2) the alternate base rate (which is primarily based on Wells Fargo's "prime" rate). Loans that accrue at the LIBOR rate, subject to the 2.5% floor, are subject to an additional margin of 8%. Loans that accrue at the alternate base rate are subject to an additional margin of 7%. The $40 million outstanding as of March 31, 2011 under the Second Lien Credit Agreement accrues interest at 10.5%.

        The Second Lien Credit Agreement contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to restrictions or requirements with respect to additional debt, liens, investments, hedging activities, acquisitions, dividends, mergers, sales of assets, transactions with affiliates and capital expenditures. In addition, the Second Lien Credit Agreement includes financial covenants substantially similar to those under the Credit Agreement, as amended by the First Amendment, and an additional covenant addressing limitations on Subsidiary's ratio of Total Proved PW10% to Total Debt (each as defined in the Second Lien Credit Agreement). As of March 31, 2011, the Company was in compliance with all covenants under the credit agreement.

Interest Incurred Under the First and Second Lien Credit Agreement

        For the quarter ended March 31, 2011, the Company incurred interest expense on the credit facility of $1.1 million. The Company capitalized the entire amount of interest costs of $1.1 million for the quarter ended March 31, 2011.

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

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7—Fair Value Measurements (Continued)

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 March 31, 2011 by level within the fair value hierarchy (in thousands):

        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 to meet its potential repayment obligations associated with the derivative transactions. At March 31, 2011, derivative instruments utilized by the Company consist of both "no cost" collars and swaps. 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.

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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 on Form 10-Q 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:

•

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;



•

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



•

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



•

geographical concentration of our operations;



•

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



•

availability of borrowings under our credit agreements;



•

termination fees related to drilling rig contracts;



•

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



•

our ability to successfully drill wells that produce oil or natural gas in commercially viable quantities;



•

failure to meet our proposed drilling schedule;



•

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



•

historical incurrence of losses;



•

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



•

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



•

limited control over non-operated properties;



•

reliance on limited number of customers;



•

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

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•

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



•

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



•

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



•

marketing and transportation constraints in the Williston Basin;



•

federal and tribal regulations and laws;



•

our current level of indebtedness and the effect of any increase in our level of indebtedness;



•

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



•

price volatility of oil and natural gas prices, and the effect that lower prices may have on our net income and stockholders' equity;



•

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;



•

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



•

effects of competition;



•

effect of seasonal factors;



•

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



•

further sales or issuances of common stock; and



•

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 the section entitled "Risk Factors" included in our Annual Report on Form 10-K. 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 section and elsewhere in this 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 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.

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        Our revenue and future growth rate depend on factors largely beyond our control such as economic, political and regulatory developments and competition from other sources of energy. Oil and gas prices historically have been volatile and may fluctuate widely in the future. Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and gas that we can produce economically and therefore could potentially lower our reserve bookings. A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and gas properties and may materially or adversely affect our future business, cash flows, results of operations, liquidity or ability to finance planned capital expenditures. Lower oil and gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher oil and natural gas prices have and may continue to result in significant non-cash mark-to-market losses being recognized on our commodity derivatives, resulting in us experiencing net losses.

        As of March 31, 2011 our primary operating areas include the following:

Williston Basin

        Williston Basin in Western North Dakota and Eastern Montana:    As of March 31, 2011, we owned an interest in approximately 112,000 gross acres and 70,000 net acres in this geologic basin. Our primary targets within the Williston Basin are the Bakken Pool consisting of the middle Bakken and Three Forks formations, collectively "Bakken", as well as other formations that produce in the basin including the Mission Canyon and Red River formations. During the first quarter of 2011, we invested capital expenditures of approximately $28.7 million related to drilling and completion operations and $4.0 million related to land leasing activities. As of March 31, 2011, we operate, or have an interest in, a total of 36 gross (18.0 net) producing wells in the Williston Basin.

Green River Basin

        Vermillion Basin of southwest Wyoming:    Our primary leaseholdings in the Green River Basin are located in an area referred to as the Vermillion Basin. As of March 31, 2011, we owned a non-operating interest in 30,000 gross (7,000 net) acres in the Vermillion Basin that is prospective for the Baxter Shale, a 3,000-foot-thick, condensate and gas-prone interval that is also referred to as the Niobrara Shale in other parts of Wyoming and Colorado. During 2010, our partner completed a well that has been turned to production facilities. Although we participated and were carried in the drilling, we did not participate in the completion operations. We will continue to evaluate the play, but have not allocated capital expenditures toward the prospect during 2011.

Recent Developments

Drilling and Completion Activity

        During the first quarter of 2011 we experienced delays in workover and completion operations as well as infrastructure construction due to harsh weather conditions. Furthermore, due to weather conditions, we experienced difficulties in transporting our crude oil from the well sites, which difficulties had a negative impact on our first quarter production. In many cases, the lack of sufficient tank storage and the constraints on oil transportation required us to shut-in our wells and production. This situation has continued into April 2011 with heavy rainfall and melting snow pack in our production areas. However, we anticipate this situation to improve in the later part of the second quarter of 2011.

        We currently expect our production for the year to be near the lower end of our earlier guidance of 5,500 average barrels of oil equivalent per day, subject to the timely completion of the wells scheduled to be completed in 2011. We expect our production to improve as we accelerate our program

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with our third and fourth operated rigs, as weather conditions continue to improve, as the backlog of wells waiting on completions are reduced, and as we complete wells on our current multi-well pads.

        During the first quarter of 2011, we completed one gross (0.68 net) well. In late March 2011, we began completion operations on two gross (1.9 net) wells that were placed on production in early April. As of May 5, 2011, we have three gross (1.6 net) wells waiting to be completed, and three gross (2.0 net) wells where drilling has been completed but the wells are located on drilling pads where we are currently drilling the final well on the pads. We expect these wells to be completed in the second and third quarters of 2011.

        During the quarter we drilled three gross (2 net) wells. Drilling operations are continuing on another two gross (1.5 net) wells. In addition, seven gross (1.7 net) non-operated wells were spud during the first quarter of 2011.

Dedicated Fracture Stimulation Team

        In the first quarter of 2011, we entered into a two-year agreement with our pressure-pumping service company whereby we will have a dedicated crew for an average of 14 days per month reconciled on a quarterly basis commencing in the third quarter 2011. This agreement formalizes our ongoing relationship with this service company and ensures continuation of the close relationship we have historically maintained. As we continue to increase our drilling rig count we would anticipate that the number of days dedicated to Kodiak would also increase.

Delivery of Third Operated Drilling Rig and Contract for Fourth Operated Drilling Rig

        We are in the process of mobilizing our third operated rig onto our Smokey Prospect area in McKenzie County. We anticipate that we will spud our first well with this rig in early May 2011. The rig was initially scheduled for delivery in the first quarter of 2011 after it completed drilling operations for another operator. However due to drilling delays, delivery of the rig was postponed. The contract on this rig is for two years. Subsequent to March 31, 2011, we entered into a contract for a fourth operated drilling rig. The rig is generally built to the same specification as our other three rigs, except it does not have a skid package, which we can add at a later date at our election. We intend to take delivery of the rig during May 2011 and it will be under contract for two years. The addition of the fourth rig will allow us to accelerate our drilling program and should compensate for a portion of the drilling days lost due to the delay of the third rig described above. The net effect to our capital budget for 2011 of adding the fourth rig, offset by delays in the first quarter of 2011 and including acreage leasing costs to-date is an expected $20 million increase.

2011 Capital Expenditures and Budget

        We have increased our 2011 capital expenditure budget by $20 million to $220 million due to the addition of a fourth operated drilling rig and expenditures for acreage acquisition to-date. These increases were partially offset by reduced spending in the first quarter primarily as the result of the delay in taking delivery of the third operated rig. We believe our initial budget captured anticipated cost increases and to date our well costs are meeting our expectations. We have estimated completed well costs of $8.5 million to $9 million plus additional costs for infrastructure associated with pipeline connections. These estimates are in line with our current cost structure. We have experienced higher costs associated with the winter months but we would expect these costs to diminish as we move into the summer operations. Our 2011 capital expenditure budget is subject to various factors, including

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market conditions, oilfield services and equipment availability, commodity prices and drilling results. Our capital budget for 2011 is comprised of the following:

•

$175 million for the drilling and completion of operated wells and related infrastructure. In the three month period ended March 31, 2011, we spent approximately $23.3 million on operated properties.



•

$40 million is allocated to non-operated drilling activity. Year-to-date we have spent $4.3 million related to the drilling progress on three gross (1.5 net) wells.



•

$4.0 million for leasehold expenditures in the first quarter in which we acquired approximately 1,200 net acres. Although our 2011 capital expenditure budget does not include additional costs related to lease acquisitions, we have continued to explore opportunities to expand our acreage position.

Capital Resources

        Our 2011 drilling program is designed to provide flexibility in identifying suitable well locations and in the timing and size of capital investment. We anticipate funding the remainder of the 2011 capital program through a combination of existing working capital, our expected operating cash flows, and additional credit that may be available under either our borrowing base or second lien term loan facilities.

        As of March 31, 2011, we have working capital of $81.8 million primarily consisting of $76.2 million of cash and equivalents. In addition, we have an existing revolving line of credit with a borrowing base that was increased to $75.0 million in April 2011 that is currently undrawn. We expect that this borrowing base will continue to increase with the addition of proved properties as a result of our ongoing drilling and completion activities.

        We anticipate that our operating cash flows will continue to increase as additional wells are placed on production. In the first quarter of 2011, our average sales volumes increased to approximately 1,860 barrels of oil equivalent per day (BOEPD), or 100% over the sales volumes for the same period of 2010. Provided we complete wells that are currently awaiting completion and that we complete new wells expected to be drilled through the remaining of 2011, and provided such wells produce at rates similar to those generated by our existing wells, we would expect our production rates and operating cash flows to grow significantly as we move through 2011. However, there can be no assurances that we will either complete such wells or that such wells will produce or generate cash flows at such levels.

        We cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings will be sufficient to fund our anticipated capital expenditures. If our existing and potential sources of liquidity through operating cash flows or expanded available borrowings are not sufficient to undertake our planned capital expenditures, we may be required to 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. 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 planned exploration and drilling program.

Our Properties

Williston Basin

        Our primary geologic target in the Williston Basin is the middle member of the Bakken Formation, the dolomitic, sandy interval between the two Bakken shales at an approximate vertical depth of 10,300-11,300 feet and the Three Forks Formation that is present immediately below the lower Bakken

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shale. As of March 31, 2011, we were operating a two-rig program. Subsequent to March 31, 2011 we took delivery of a third drilling rig and executed a contract for a fourth drilling rig. In addition, our joint venture partner on a portion of our Dunn County leasehold is operating one drilling rig on the lands it operates. Our working interest will vary in the wells drilled by these non-operated rigs but we expect to have a 50% interest with respect to a significant number of the wells drilled in 2011.

        Our Williston Basin leasehold is largely contiguous and by virtue of our high working interest and operatorship, we can control the development pace and location of our surface facilities. We believe this strategy, combined with pad drilling and long laterals, will maximize the efficiency of our drilling and completion programs as well as minimize the infrastructure required to connect our wells to sales pipelines. As a result, we are able to plan our locations to minimize the number of wells required to hold our acreage by establishing production within the primary terms of our leases.

Dunn, Mountrail and McLean Counties, North Dakota (59,000 gross and 34,000 net acres)

        During 2011, we have continued to develop our Dunn County leasehold where we have consistently utilized one of our drilling rigs. We are currently drilling the fourth well on a four-well pad. Once drilling operations are finished, this pad will be prepared for completion operations that are expected to occur during the later part of the second quarter and the early part of the third quarter of 2011. The wells on this pad have been drilled in a manner that will continue to provide us information as to the productivity of the Three Forks Formation as well as additional testing of wellbore density within the middle Bakken Formation and communication between the middle Bakken and Three Forks formations.

McKenzie County, North Dakota (39,000 gross and 27,000 net acres)

        On our leasehold in McKenzie County, N.D., we completed two wells in early April 2011. First, the Koala #9-5-6-12H3 (95% WI/78% NRI), an approximate 9,200-foot horizontal lateral was successfully completed in 22 stages in the Three Forks Formation. During a 24-hour period, the well recorded production of 1,919 barrels of oil ("BO") and 2.45 million cubic feet of natural gas ("MMcf"), or 2,327 barrels of oil equivalent ("BOE"). Over the first 21 days of production, this well produced approximately 17,900 BO and 22.9 MMcf, for an average of 1,035 BOE per day. This Three Forks well was drilled 700 feet from the middle Bakken well discussed below in an ongoing effort to evaluate communication between the middle Bakken and the Three Forks formations. By successfully completing the Koala #9-5-6-12H3 well, we believe we have demonstrated the productive potential of the Three Forks Formation as an oil-prone reservoir system on this part of our McKenzie County core operating area.

        In addition, the Koala #9-5-6-5H well (95% WI/78% NRI), an approximate 9,000-foot horizontal lateral, was successfully completed in 24 stages in the middle Bakken Formation. During a 24-hour period, the well recorded production of 2,526 BO and 3.1 MMcf, or 3,042 BOE. Over the first 14 days of production, this well produced approximately 17,000 BO and 9.3 MMcf, for an average of 1,335 BOE per day.

        We currently have two wells awaiting completion in the Koala area that were drilled on a two-well pad, the Koala #3-2-11-14H (52% WI/42% NRI), and the Koala #3-2-11-13H (53% WI/43% NRI) wells. These two well bores have been drilled approximately 1,300 feet apart in the middle Bakken in an effort to test well bore density within the drilling unit. These wells are projected to be completed in the second quarter of 2011.

        In February 2011, we completed the Grizzly #13-6H well in the middle Bakken Formation. This well in western McKenzie County was a reentry well where we drilled out a short horizontal lateral of approximately 3,100 feet and fracture stimulated using 10 stages with a cemented liner. Initial

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production from the well was 378 BOEPD and 128 MCF of natural gas per day or 399 BOEPD. During the first 60 days of production, the well averaged 120 BOPD.

        The following summary provides a tabular presentation of data pertinent to our Williston Basin drilling and completion activities targeting the Bakken during 2010 and 2011 (gas is converted on a 6 Mcf to 1 barrel of oil basis):

Kodiak Oil & Gas Corp.
North Dakota (Bakken and Three Forks) Drilling and Completion Activities

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Our Leasehold

        As of April 1, 2011, we had several hundred lease agreements representing approximately 157,000 gross and 90,000 net acres primarily in the Williston and Green River Basins. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

        We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Substantially all of our proved oil and natural gas properties are pledged as collateral for borrowings under our revolving line of credit and second lien facilities.

        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 during the next three years and have no options for renewal or are not included in federal units:

Operating Results

Production and Sales Volumes, Average Sales Prices, and Production Costs

        The Bakken is the only field (as such term is used within the meaning of applicable regulations of the SEC) that contains more than 15% of our total proved reserves. At December 31, 2010, this field contained 99% of our total proved reserves, nearly all of which are located in Dunn and McKenzie

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Counties. The following table discloses our oil and gas production and sales volumes from the Bakken field, from our other fields combined and in total, for the periods indicated:

        Sales prices received, and production costs per sold BOE for the three months ended March 31, 2011 and 2010 are summarized in the following table:

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Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010

        Oil sales revenues.    Oil sales revenues increased by $7.5 million to $13.0 million for the three months ended March 31, 2011, as compared to oil sales of $5.5 million for the same period in 2010. Our oil sales volume increased 104% to 157.4 thousand barrels (MBbls) in the first quarter of 2011 as compared to 77.2 MBbls in the first quarter of 2010. The volume increase is due to the oil volumes produced from our Bakken development. However, these volumes were negatively impacted in the first quarter of 2011 by severe winter conditions which caused delays in transportation and reduced well completion activity. Also contributing to the increase in sales revenue was the increase in the average price we realized on the sale of our oil. Our net price received increased from $71.08 per barrel for the quarter ended March 31, 2010, to $82.72 per barrel for the quarter ended March 31, 2011.

        Natural Gas sales revenues.    Natural gas sales volumes increased to 62,200 Mcf in the first quarter of 2011 compared 43,100 Mcf in the same period in 2010. The average price we realized on the sale of our natural gas was $5.04 per Mcf in the 2011 period compared to $5.41 per Mcf in 2010. The increase in our natural gas sales volumes is largely a result of production and sales of associated gas from our Bakken properties offset by a decline of our Wyoming assets that historically contributed a majority of our natural gas production. Although the majority of our gas from the Bakken wells to-date has been flared, late in 2010, we began connecting our wells to third party pipelines that gather and transport the gas to processing plants and sales pipelines. We expect that a majority of our remaining wells will be connected to gas pipelines during 2011 which will allow us to capture the related sales revenue. Industry-wide in the Williston basin, there is currently a shortage of gas gathering and processing capacity which has limited our ability to sell our gas production. During 2011, we expect that additional third-party facilities will come online which should allow additional gas volumes to be gathered, processed and sold.

        Loss on commodity price risk management activities.    Primarily due to the increase in crude oil price during the first quarter of 2011, for the three months ended March 31, 2011, we incurred a total loss on our risk management activities of $9.7 million. This loss is a result of our hedging program used to mitigate our exposure to commodity price fluctuations that may inhibit our ability to fund our capital expenditure budget or other obligations. This loss was comprised of approximately $342,000 of realized losses for transactions that were settled in the first quarter of 2011 and $9.4 million of unrealized losses for the mark-to-market valuation of forward transactions. The unrealized loss is a non-cash adjustment for the value of our risk management transactions at March 31, 2011. These transactions will continue to change in value and we will likely add to our hedging program. Therefore we expect our net income to continue to reflect the volatility of commodity price forward markets. Our cash flows are not affected by unrealized gains and losses on commodity risk management activities, but rather, will be affected when gains or losses are realized upon settlement of the underlying transactions at the current market prices at that time.

        Oil and gas production expense.    Our oil and gas production expense increased by $1.3 million to $2.6 million for the quarter ended March 31, 2011 as compared to the same period in 2010. The increase is due to an $861,000 increase in production taxes and a $494,000 increase in lease operating expenses ("LOE"). The production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue. LOE increased year over year due to a higher number of wells that we operate or participate in. On a per unit basis, LOE decreased from $6.53 per barrel sold in 2010 to $5.97 in 2011. This decrease is primarily related to increased volumes sold as compared to a lesser increase in nominal costs. The largest cost driver in our Williston Basin operations is the disposal of flowback water used in the well completion operations. We expense the water handling costs once oil production is established. The timing of completions and resulting water handling costs will cause variations in the LOE per barrel ratio on a quarter-to-quarter basis. To date, this water has been transported by truck to third party disposal facilities. Late in 2010, we began connecting our wells to

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third party pipelines that will transport water directly to disposal facilities. We expect that a majority of our remaining wells will be connected to water pipelines during 2011, which will substantially reduce our water-related costs. However, we expect to continue to experience volatility relative to the timing of our well completion work.

        Depletion, depreciation, amortization and abandonment liability accretion ("DDA") expense.    Our depletion, depreciation, amortization and abandonment liability accretion expense increased by $2.4 million to $3.7 million for the three months ended March 31, 2011, from $1.3 million for the same period in 2010. This increase is due to increased volumes sold in 2011 as sales increased by approximately 83,400 BOE over the same period. On a per unit basis, DDA increased from $15.65 per barrel sold in the first quarter of 2010 to $22.18 per barrel sold in 2011. This increase is due to increased well costs as compared to reserves as estimated in our annual reserve report. Beginning in 2010, we have predominantly completed our wells using a greater number of fracture stimulation stages and increased volumes of proppant. These factors have increased the well completion costs but we believe that the higher upfront costs will generate overall higher returns through greater production volumes and total oil and gas reserves. Currently, because of the early stages of development of our Bakken play, our reserves, especially for undeveloped locations, include the increased well costs but not the improved reserves. We believe that as our improved results are reflected in our future estimated reserves, the DDA rate per unit will decrease over time. Also contributing to the increased DDA rate is the allocation of the purchase price to producing properties related to our acquisition in the fourth quarter of 2010.

        General and administrative ("G&A") expense.    G&A expense increased by $2.6 million to $4.7 million for the quarter ended March 31, 2011, from $2.1 million for the same period in 2010. This increase is primarily due to the growth in personnel and related costs as we have expanded our operational activities related to the Bakken development. Total employees increased to 40 at March 31, 2011, from 20 at March 31, 2010.

        Our G&A expense includes the non-cash expense for share-based compensation for stock options and restricted stock unit grants under our 2007 Stock Incentive Plan. For the three months ended March 31, 2011, this expense was $1.5 million as compared to $850,000 in 2010.

        Operating income.    Our operating income was approximately $2.4 million for the quarter ended March 31, 2011, as compared to approximately $1.1 million for the quarter ended March 31, 2010. This 122% increase in operating income from the first quarter of 2010 compared to the first quarter of 2011 is attributed to our on-going successful completions of wells in our Bakken play as well as crude oil price improvement from the first quarter of 2010 to the first quarter of 2011.

        Net loss.    Our net loss was approximately $7.2 million for the quarter ended March 31, 2011, as compared to net income of approximately $1.0 million for the quarter ended March 31, 2010. Although our revenue, net of production expenses, was higher compared to 2010, our 2011 net loss was negatively impacted by increased DDA, G&A and, most significantly, the $9.4 million unrealized loss on risk management activities discussed above.

Commitments and Contingencies

        For a 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 March 31, 2011 and December 31, 2010.

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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, 2010, which is incorporated herein by reference.

Recently Issued Accounting Pronouncements

        None.

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. The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. We manage this commodity price risk exposure through the use of derivative financial instruments entered into with third-party counterparties. Currently, we utilize swaps and "no premium" collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes.

        We use no premium collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements. These contracts are settled monthly. When the settlement price (the market price for oil or natural gas on the settlement date) for a period is above the ceiling price, we pay our counterparty. When the settlement price for a period is below the floor price, our counterparty is required to pay us. All hedges are accounted for using mark-to-market accounting.

        We use swaps to fix the sales price for our anticipated future oil production. Upon settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating market price, as defined in each instrument. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to us.

        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 Oil & Gas (USA) Inc., is currently a party to derivative contracts with one counterparty, and the Company is a guarantor of Kodiak Oil & Gas (USA) Inc. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparties. 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.

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        The Company's commodity derivative contracts as of March 31, 2011 are summarized below:

        The following table details the fair value of the derivatives financial instruments as of March 31, 2011 and December 31, 2010, by category (in thousands):

        The Company determines the estimated 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 the 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 to meet its potential repayment obligations associated with the derivative transactions.

ITEM 4.    CONTROLS AND PROCEDURES

        Management, with the participation of our Chief Executive Officer and Chief Financial Officer, 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 March 31, 2011. On the basis of this review, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures

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are effective to ensure 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.

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

        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, 2010, as filed with the SEC on March 3, 2011. The risk factors in our Annual Report on Form 10-K for the year ended December 31, 2010, 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.

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.

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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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