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, 2008 and the following:

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º our future financial and operating performance;

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º our business strategy;

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º 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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º market demand;

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º drilling of wells;

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

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º the uncertainty of reserves estimates and reserves life;

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

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

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º our dependence on key personnel;

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

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º health, safety and environmental risks;

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º uncertainties as to the availability and cost of financing;

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º unforeseen liabilities arising from litigation; and

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º 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

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. ("Kodiak," "we" or the "Company") 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 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. Significant prospects in our portfolio currently include:

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º Bakken oil play in Mountrail and Dunn Counties, North Dakota: As of June 30, 2009, we owned an interest in approximately 54,000 gross (37,000 net) acres in this highly prospective play. All of our acreage in this play is located on the Fort Berthold Indian Reservation (FBIR) in Dunn County, N.D. We anticipate continuing drilling operations through year-end which may include drilling up to four additional wells. We have completed four wells in this play and brought them on to production during the second quarter of 2009. We anticipate completion of at least five additional wells in 2009 with two of these in the third quarter and the balance in the fourth quarter. During the first half of 2009, we incurred capital expenditures of approximately $11.5 million largely related to the drilling operations on this oil play where we have drilled six wells to date and have recently spud our seventh well. We anticipate total capital expenditures in the Bakken oil play to be approximately $21.0 million for the entire year.

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º Vermillion Basin of southwest Wyoming: In the first quarter of 2008, we entered into an exploration and development agreement with Devon Energy Production Company, L.P. ("Devon"), a wholly owned subsidiary of Devon Energy Corp., as part of our strategy to develop our play in the Vermillion Basin. As of June 30, 2009, we owned an interest in approximately 44,000 gross (17,000 net) acres in the Vermillion Basin. During 2008, Devon drilled four wells on the prospect acreage, two of which were drilled horizontally and are awaiting completion.

Kodiak's results of operations and financial condition are significantly affected by the success of our exploration activity, the resulting production, oil and natural gas commodity prices and the costs related to operating our properties. As is common with companies engaged in the exploration of early resource plays, our financial position and results of operations change significantly from period to period.

In May 2009, we entered into agreements to sell 9.6 million shares of our common stock to certain institutional investors, in a non-brokered registered direct offering. The common stock offered was registered on a universal shelf registration statement on Form S-3 (No. 333-152311) that was filed with the SEC on July 14, 2008 and declared effective by the SEC on July 24, 2008. The aggregate gross proceeds from the offering were $7.2 million, and the aggregate net proceeds, after deducting offering expenses, were $7.1 million. The net proceeds will be used primarily for drilling and completion

activities on our leases in the Bakken oil play located on the FBIR in North Dakota and for other general corporate activities.

In July 2009, we entered into an agreement effective June 30, 2009 to acquire an additional 31.25% working interest in the Tall Bear prospect area. Concurrently, we entered into a separate agreement, made effective July 1, 2009, with a private industry partner whereby we agreed to convey certain of our leasehold to the joint venture partner. The net result of these two transactions resulted in a sell-down of 3,300 net acres of our leasehold in the Charging Eagle and Tall Bear prospects, now referred to as the Twin Buttes area. After netting the costs to acquire the 31.25% working interest in the Tall Bear prospect area, we realized $1.85 million in cash and we will pay 50% of the first five wells drilled in the Twin Buttes area for our 60% working interest, proportionally reduced. The net cash of $1.85 million was received in July 2009.

Effective August 1, 2009, the Company entered into an amendment with Devon whereby we have assigned approximately 50% of our current interest in the Vermillion Basin prospect area in southwest Wyoming to Devon. In return, we will be carried for our remaining 25% working interest in two horizontal completions on wells that were drilled earlier, one located in the Coyote Flats Unit and the other located in the Horseshoe Basin Unit. Furthermore, we will be relieved of all previously recorded indebtedness to Devon for costs associated with exploration work that exceeded the $30 million carried interest previously disclosed. Therefore, as of August 1, 2009, neither party will have amounts due to nor due from the other party nor will we incur any further costs through the completion, equipping or tying into sales of the two horizontal wells mentioned above. Completion work is scheduled to be commenced during the third quarter of 2009.

During the second quarter of 2008, we entered into contracts for the use of two new-build drilling rigs. The first rig was placed into operation in November 2008 and entails a two-year drilling commitment and specific termination fees if drilling activity is cancelled or never commenced. Under the terms of the Second Rig Contract, we were initially scheduled to take delivery of the second rig in February 2009 but, effective August 2009, the Company and the contractor have agreed to an amendment to the Second Rig Contract to defer such delivery. Under the amendment, the Company will make monthly Delay Payments until the earlier of delivery of the second rig or the expiration of twelve months totaling up to an aggregate of $1.9 million. If we take delivery of the second rig during this 12-month period, a portion of the Delay Payments may be applied in the form of a credit against future operating charges incurred by the Company under the Second Rig Contract, which has a two-year drilling commitment. The actual amount of the credit will decrease as time passes creating an incentive for the Company to take delivery or locate a party to assume the rig commitment. In the event that the Company does not take delivery of the rig before the expiration of the 12-month period or cancels the Second Rig Contract after delivery, the Company may be required to pay a termination fee. The maximum termination fee payable by the Company would be $5.6 million, against which, under certain circumstances, some or all of the Delay Payments may be applied in the form of a credit.

Recent Developments

Williston Basin Operations-Dunn County, North Dakota

In Dunn County, North Dakota, Kodiak's exploration efforts target oil and gas production from the middle member between the upper and lower Bakken shales, which comprise the source rock for existing hydrocarbons. The Three Forks/Sanish Formation, a productive interval lying directly below the lower Bakken shale, is also expected to be a future exploration target. Commercial production from the Three Forks / Sanish Formation is being reported by operators in the immediate area.

Drilling and Completion Activity

Exploration and development drilling activities continued through the second quarter of 2009. In an effort to minimize surface disturbance and to lower the mobilization costs between wells, Kodiak has developed its drilling program using pad drilling. Each pad is designed to allow the drilling of two vertical well bores that are located approximately 50 feet apart. From each of the vertical well bores we drill horizontally in two directions, while still maintaining the preferred orientation of the lateral to best intersect the natural fractures from the reservoir. In some cases we have varied the length of the lateral in order to evaluate the economics between shorter and longer laterals. Drilling of both laterals must be completed before any completion work is initiated.

Upon completion of the drilling activity, the well-site is cleared and prepared to allow for the commencement of completion activities. This process typically can take two to four weeks. Our practice has been to complete one of the wells on the pad, allow for a two-week flowback period which also provides adequate time to reload sand and water for the second completion from the pad. The first well completed on the pad is shut in during completion of the second well. Once all completion work is finished both of the wells are put on to production.

The following summary provides a tabular presentation of data pertinent to Kodiak's middle Bakken wells drilled, completed and in progress.

                                Kodiak Oil & Gas Corp. Drilling and Completion Activities
                  WI /                                                                        First 30 Day
                  NRI      Days to    Length of    Completion      Number      IP 24-Hour         Oil
Well              (%)        TD*       Lateral        Date       of Stages     Test BOE/D      Production        Note
MC #16-34-2H         60          41       4,169'     4/23/2009            8            711            8,397     flowing
                    /49                                                                                          well
MC #16-34H         60 /          36       4,150'      5/4/2009            5          1,394           13,406     flowing
                     49                                                                                          well
TSB #16-8-7H       37.5          28       8.995'      6/7/2009           15          1,856           21,542     flowing
                      /                                                                                          well
                   30.5
TSB #16-8-16H        50          31       4,465'     6/18/2009            5            811           12,288     flowing
                    /41                                                                                          well
TSB #14-33-28H       50          31       8,313'      8/3/2009           15              -                -   Completing
                    /41
TSB #14-33-6H        50          26       4,163'     8/24/2009            6              -                -   Completing
                    /41
CE #1-22-10H         55           -     **9,000'             -                           -                -    Drilling
                    /45
CE #1-22-23H         60           -     **5,000'             -                           -                -   Spud after
                    /50                                                                                       CE#1-22-10H
TB #16-15-10H        60           -     **9,000'             -                           -                -   Spud after
                    /50                                                                                       CE#1-22-23H


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   º *

º **
º Approximate length of lateral

Production, Average Sales Prices, and Production Costs

Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. Commodity prices are beyond our control and are difficult to predict. Market prices reflect worldwide concerns regarding economic conditions and demand for petroleum products, amid a host of uncertainties caused by political instability, fluctuations in the U.S. dollar and crude oil refining constraint. We receive lower prices for our oil and gas than what is posted on the New York Mercantile Exchange (NYMEX). The price differentials received for our products vary from month to month, and we do not currently hedge our commodity sales in place. As production volumes increase, we will consider an appropriate risk management strategy.

The Company's oil and gas sales volumes are directly related to the results of its exploratory and acquisition activities. Production volumes may vary monthly as various wells are completed or maintained in an effort to provide optimal production. Sales volumes, prices received and production costs are summarized in the following table for the three and six month periods ended June 30, 2009 and June 30, 2008.

                                 For the three months ended          For the six months ended
                              June 30, 2009     June 30, 2008    June 30, 2009     June 30, 2008
Sales Volume:
Gas (Mcf)                             58,878            36,108          158,572           102,708
Oil (Bbls)                            35,314            13,010           51,800            28,858
Production volumes (BOE)              45,127            19,028           78,229            45,976
Price:
Gas ($/Mcf)                    $        2.20     $       12.80     $       2.60      $       9.04
Oil ($/Bbls)                   $       52.69     $      115.42     $      45.48      $     100.97
Production costs ($/BOE):
  Lease operating expenses     $        2.37     $       54.75     $       3.12      $      39.94
  Production and property      $        4.88     $       11.23     $       2.48      $       8.09
  taxes
  Gathering,                   $        0.36     $        1.40     $       0.69      $       1.24
  Transportation & &
  Marketing

Results of Operations

For the Three Months Ended June 30, 2009 compared to the Three Months Ended June 30, 2008

The Company reported a net loss for the three months ended June 30, 2009 of $0.5 million, compared to a net loss of $1.9 million for the same period in 2008. This improvement in net income is primarily attributable to the new production from our FBIR wells, which began production in the second quarter of 2009, and from new wells coming on to production in late 2008 in our Vermillion Basin area. Additionally, we had production from our existing wells during the three month period ended June 30, 2009 that were shut-in for workover activities in the second quarter of 2008. For the period, our volumes on a BOE basis, increased from 19,028 BOE in the second quarter of 2008 to 45,127 BOE during the second quarter of 2009. This 137% increase in volumes was however offset by lower oil and natural gas pricing during the three month period ended June 30, 2009 versus the three month period ended June 30, 2008. Total natural gas price realizations decreased 83% to $2.20 per Mcf for the three month period ended June 30, 2009, compared to $12.80 per Mcf for the same period in 2008. Oil price realizations declined by 54% to $52.69 per barrel for the three month period ended June 30, 2009, compared to $115.42 for the same period in 2008. Although we increased our production for the period, lower pricing offset this increase, resulting in total revenue that was

approximately equal during the three month period ended June 30, 2009 compared to the same period in 2008.

                                              For the three months ended
                                           June 30, 2009      June 30, 2008
        Financial Results
        Total revenue                       $   2,013,030     $    2,000,690
        Total costs and expenses            $   2,551,184          3,899,131
        Net loss                            $    (538,154 )   $   (1,898,441 )
        Diluted net loss per common
        share                               $       (0.01 )   $        (0.02 )
        Capital Resources and Liquidity
        Cash and cash equivalents at end
        of the period                       $   3,821,907     $    1,199,427
        Net cash provided by (used in)
        operating activities                $   1,779,759     $   (2,741,050 )
        Capital expenditures-oil and gas
        properties excluding accruals
        and proceeds from divestitures      $   5,590,294     $    6,042,791
        Adjusted EBITDA (see below
        discussion)                         $     582,702     $     (664,735 )

Oil and Gas Revenue and Production

During the three-month period ended June 30, 2009, as compared to the same period in 2008, natural gas production volumes increased 63% due to production from new wells in our Vermillion Basin area which came on-line in the fourth quarter of 2008. Crude oil production volumes increased 171% due to new production from completion operations on our FBIR area during the second quarter of 2009. Total gas price realizations decreased 83% to $2.20 per Mcf for the three month period ended June 30, 2009, compared to $12.80 per Mcf for the same period in 2008. Oil price realizations declined by 54% to $52.69 per barrel for the three month period ended June 30, 2009, compared to $115.42 for the same period in 2008. Although both oil and natural gas production increased in the second quarter of 2009 compared to 2008, oil and gas revenues of approximately $2.0 million for the three month period ended June 30, 2009, were approximately the same as revenue for the equivalent period in 2008.

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of $343,674 during the three month period ended June 30, 2009, as compared to $1,282,618 during the same period in 2008. In the second quarter of 2008, we performed workover operations on our producing Bakken oil wells in McKenzie County, N.D. 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. Excluding workover operations but including both lease operating and production tax expense, our lease operating costs increased by approximately $61,000 for the three month period ended June 30, 2009, as compared to the same period in 2008. The increase is attributed to new wells in production during the second quarter of 2009 as compared to the second quarter of 2008.

Depletion, Depreciation and Amortization

Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was $532,454 for the three month period ended June 30, 2009, compared to $786,777 for the same period in 2008. DD&A expense decreased during the quarter due to the impairment charges taken in 2008 which reduced the full cost pool by $47.5 million year over year thereby decreasing the DD&A expense recorded.

Ceiling Test Impairment

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower of unproved properties that are subject to amortization. For the three months ended June 30, 2009 and 2008, no impairment charges were recorded.

General and Administrative Expense

The Company's general and administrative costs were approximately $1.7 million for the three months ended June 30, 2009 compared to approximately $1.8 million for the same period in 2008. This 8% reduction for the period is primarily due to our ongoing cost containment efforts. Excluding the non-cash stock-based compensation expense in each period, due to our ongoing cost containment efforts, our general and administrative costs related to employee costs, travel, legal and consulting expenses declined by approximately $296,000 or 21% during the three month period ended June 30, 2009 as compared to the same period in 2008. We recorded higher stock- based compensation expense of approximately $.6 million for the three months ended June 30, 2009 compared to approximately $.4 million recorded for the same period in 2008, related to options and restricted stock issued to officers, directors and employees. The increase in the stock-based compensation expense recorded during the three month period ended June 30, 2009 was primarily due to an approximate $321,000 reversal of terminated stock options and restricted stock during the period ended June 30, 2008, as compared to a reversal of stock-based compensation expense related to the expired performance-based stock options of only approximately $122,000 in the three month period ended June 30, 2009.

EBITDA

In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gains or losses on foreign currency exchange, non-cash stock-based compensation expense, impairment 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, future capital expenditures and servicing of borrowings under the Company's Credit Facility. The Company's Adjusted EBITDA increased by approximately $1.3 million to approximately $0.6 million for the three months ended June 30, 2009 from the same period in 2008. The increase in Adjusted EBITDA was primarily the result of the increase in both oil and natural gas production during the period as compared to the same period in 2008. 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 Adjusted EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled

measures employed by other companies. A reconciliation of Adjusted EBITDA and net income for the three months ended June 30, 2009 and 2008 is provided in the table below:

                                                Three
                                               months
                                                ended      Three months
. . .