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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, 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 March 31, 2010

Commission File No. 001-32920

LOGO

(Exact name of registrant as specified in its charter)

Yukon Territory

N/A(State or other jurisdiction
of incorporation or organization)

(I.R.S. Employer
Identification No.)


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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit
and post such files). Yes o    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 definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o

Accelerated filer ý

Non-accelerated filer o (Do not check if a smaller
reporting company)

Smaller reporting company o


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

119,267,931 shares, no par value, of the Registrant's Common Stock were issued and outstanding as of May 4, 2010.



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Table of Contents



KODIAK OIL & GAS CORP.    INDEX



PART 1FINANCIAL INFORMATION


2ITEM 1.

FINANCIAL STATEMENTS


2ITEM 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


19ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


30ITEM 4.

CONTROLS AND PROCEDURES


30PART IIOTHER INFORMATION


32ITEM 1.

LEGAL PROCEEDINGS


32ITEM 1A.

RISK FACTORS


32ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS


32ITEM 3.

DEFAULTS UPON SENIOR SECURITIES


32ITEM 4.

RESERVED


32ITEM 5.

OTHER INFORMATION


32ITEM 6.

EXHIBITS


33SIGNATURES


34


1

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Table of Contents

PART 1FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED BALANCE SHEETS        (UNAUDITED)

March 31,
2010

December 31,
2009ASSETSCurrent Assets:Cash and cash equivalents

$
10,567,026

$
24,885,546Accounts receivableTrade


5,595,388


2,562,779Accrued sales revenues


3,607,513


1,909,221Inventory, prepaid expenses and other


11,689,383


7,647,870Total Current Assets


31,459,310


37,005,416Oil and gas properties (full cost method), at cost:Proved oil and gas properties


129,135,266


123,259,252Unproved oil and gas properties


12,298,121


12,068,156Wells in progress


4,562,156


2,691,107Less-accumulated depletion, depreciation, amortization, accretion and asset impairment


(97,056,180
)

(95,782,438
)Net oil and gas properties


48,939,363


42,236,077Other property and equipment, net of accumulated depreciation of $305,891 in 2010 and $284,535 in 2009


501,439


441,531Restricted investments


209,899


Total Assets

$
81,110,011

$
79,683,024LIABILITIES AND STOCKHOLDERS' EQUITYCurrent Liabilities:Accounts payable and accrued liabilities

$
7,218,195

$
7,742,617Advances from joint interest owners


632,358


951,815Commodity price risk management liability


122,230


Total Current Liabilities


7,972,783


8,694,432Noncurrent Liabilities:Asset retirement obligation


1,261,071


1,060,210Total Liabilities


9,233,854


9,754,642Commitments and ContingenciesNote 5Stockholders' Equity:Common stockno par value; unlimited authorizedIssued and outstanding: 119,092,931 shares in 2010 and 118,879,931 shares in 2009Contributed surplus


176,758,325


175,791,301Accumulated deficit


(104,882,168
)

(105,862,919
)Total Stockholders' Equity


71,876,157


69,928,382Total Liabilities and Stockholders' Equity

$
81,110,011

$
79,683,024


THE
ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
FINANCIAL STATEMENTS

2

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Table of Contents

KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS        (UNAUDITED)

For the Three Months Ended
March 31,2010

2009Revenues:Gas production

$
233,241

$
282,474Oil production


5,487,724


495,259Unrealized loss on risk management activities


(122,230
)

Interest income


10,184


13,627Total revenue


5,608,919


791,360Cost and expenses:Oil and gas production


1,222,233


148,529Depletion, depreciation, amortization and accretion


1,320,605


355,340General and administrative


2,085,331


1,915,098Total costs and expenses


4,628,169


2,418,967Net income (loss) attributable to common stock

$
980,750

$
(1,627,607
)Net income per common share:Basic

$
0.01

$
(0.02
)Diluted

$
0.01

$
(0.02
)Weighted average shares outstanding:Basic


118,931,087


95,129,431Diluted


120,588,940


95,129,431


THE
ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
FINANCIAL STATEMENTS

3

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Table of Contents

KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS        (UNAUDITED)

For the Three Months Ended
March 31,2010

2009Cash flows from operating activities:Net income (loss)

$
980,750

$
(1,627,607
)Reconciliation of net income (loss) to net cash (used in) operating activities:Depletion, depreciation, amortization and accretion


1,320,605


355,340Change in fair value of commodity price risk management activities, net


122,230


Stock based compensation


854,345


781,389Changes in current assets and liabilities:Accounts receivable-trade


(3,032,609
)

(2,083,245
)Accounts receivable-accrued sales revenue


(1,698,292
)

(241,092
)Prepaid expenses and other


(529,750
)

380,077Accounts payable and accrued liabilities


(423,939
)

(38,253
)Net cash (used in) operating activities


(2,406,660
)

(2,473,391
)Cash flows from investing activities:Oil and gas properties


(7,446,700
)

(3,817,427
)Equipment & prepaid drilling


(81,427
)

Prepaid tubular goods


(4,286,514
)

467,704Restricted investment


(209,899
)

249,272Net cash (used in) investing activities


(12,024,540
)

(3,100,451
)Cash flows from financing activity:Proceeds from the issuance of shares


112,680


Net cash provided by financing activities


112,680


Net change in cash and cash equivalents


(14,318,520
)

(5,573,842
)Cash and cash equivalents at beginning of the period


24,885,546


7,581,265Cash and cash equivalents at end of the period

$
10,567,026

$
2,007,423Supplemental cash flow informationOil & gas property accrual included in Accounts payable and accrued liabilities

$
1,021,000

$
1,097,060Asset retirement obligation

$
175,354

$
71,514


THE
ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
FINANCIAL STATEMENTS

4

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Table of Contents

KODIAK OIL & GAS CORP.        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1Organization

Description of Operations

Kodiak Oil & Gas Corp. (together with its subsidiary, "Kodiak" or 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 common shares of the Company are listed for trading on the
NYSE Amex LLC and the Company's corporate headquarters are located in Denver, Colorado, USA.

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

Note 2Basis of Presentation and Significant Accounting Policies

Basis of Presentation

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

Liquidity and Capital Resources

Kodiak's 2010 announced capital expenditure budget of approximately $60 million is primarily allocated to drilling and
completing wells. If we identify acreage that meets our strategic requirements, we may re-allocate our capital expenditure budget to permit us to complete a potential acreage acquisition.
Alternatively, depending on the availability and terms of capital resources that may be available to us, we may increase our capital expenditure budget to allow us to acquire additional acreage. In
the second quarter of 2010, the Company announced one such acquisition as described below under the heading, "Acquisitions" in Note 9Subsequent Events.

We
expect to fund our capital budget primarily from cash on hand, anticipated cash flows from operations, prepaid tubular goods and borrowings under a potential reserve-based revolving
line of credit that is discussed in more detail below. If our existing and potential sources of liquidity are not
sufficient to undertake our planned or revised capital expenditures, we may alter our drilling program, pursue joint ventures with third parties, sell interest in one or more of our properties or sell
equity or debt securities. There can be no assurance that any such transactions can be completed or that such transactions will satisfy our operating capital requirements. If we are not successful in
obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our planned expenditures or restructure our
operations, and we would be unable to implement our original exploration and drilling program.

During
the second quarter of 2010, after discussions with several financial institutions regarding the establishment of a reserve-based revolving line of credit, Kodiak has begun the
process to enter into a line of credit with a large commercial bank. The Company cannot give assurance that a credit facility will be available to us on terms acceptable to us, or at all. If we borrow
funds under a new credit agreement, we will be obligated to make periodic interest or other debt service payments and may be subject to additional restrictive covenants. The ability to borrow funds is
dependent on a number of variables, including our proved reserves, and assumptions regarding the price at which oil and natural gas can be sold.

5

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Use of Estimates in the Preparation of Financial Statements

The unaudited financial statements included herein were prepared from the records of the Company in accordance with generally accepted
accounting principles in the United States applicable to interim financial statements and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair
statement of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the Company's Annual Report on
Form 10-K filed with the Securities and Exchange Commission (the "SEC") for the year ended December 31, 2009. The current interim period reported herein should be read in
conjunction with the financial statements and summary of significant accounting policies and notes included in the Company's Annual Report on Form 10-K for the year ended
December 31, 2009.

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. Our most significant financial estimates are associated with our estimated proved oil and gas reserves.

Cash and Cash Equivalents

Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original 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 tubular goods and surface equipment required for the Company's
drilling program. As of March 31, 2010 we had approximately $10.8 million (consisting of $8.4 million of tubular goods and surface equipment that are inventoried in third-party
yards and $2.4 million of deposits for tubular goods that will be delivered later this year at such time that the tubular goods are required). In respect of the $2.4 million tubular
goods deposit, as of March 31, 2010, the Company estimates that an additional $4.8 million will be paid to complete the purchase and if the purchases are not completed the deposits would
be forfeited. At December 31, 2009 the Company had $7.3 million in tubular goods and surface equipment. The cost basis of the tubular goods is either depreciated as a component of oil
and gas properties once the inventory is used in drilling operations or billed to our partners through joint interest billings. The Company records tubular goods inventory at the lower of cost or
market value. As of March 31, 2010, and December 31, 2009, respectively, the Company's analysis of the difference between cost compared to market values for tubular goods not designated
for specific wells was not deemed material.

Restricted Investment

The restricted investment balance as of March 31, 2010, is comprised of: (a) $175,000 certificate of deposit to
collateralize a surety bond to provide for state bonding requirements for plugging and

6

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

abandonment
liabilities; and (b) $34,899 certificate of deposit to collateralize the costs of office improvements that will be released over the remaining term of the lease.

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 has, on an ongoing basis, 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 these costs. A significant
alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost 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 as determined by the Company's engineers and audited (annually) by independent petroleum engineers. 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 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 the three months ended March 31, 2010 and 2009 no unproved land costs were impaired.

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

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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 in accordance with applicable rules established by the SEC and may be adjusted based on that data.

Costs
of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether
impairment has occurred. 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 the full cost pool and
becomes subject to depletion calculations. Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based
on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure. 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.

There
were no impairment charges recognized for the three month periods ended March 31, 2010 and 2009, respectively.

Wells in Progress

Wells in progress at March 31, 2010 and December 31, 2009 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

8

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

are
then transferred to proved property when the wells are completed 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 impairment. In the three months ended March 31,
2010 and 2009, respectively, no unproved properties were impaired.

Deferred Financing Costs

Deferred financing costs include legal, engineering and accounting fees incurred in connection with the Company's Credit Agreement,
which are being amortized over the two-year term of the Credit Facility (see Note 6). The Company recorded amortization expense of $16,992 in the three month period ended
March 31, 2010. In March 2010, the Company terminated its Credit Facility and therefore, as of March 31, 2010 all deferred financing costs have been fully amortized.

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.

Commodity Derivative Instrument

In February 2010, the Company, through its wholly-owned affiliate, Kodiak Oil & Gas (USA) Inc. ("Kodiak USA") entered
into a commodity derivative contract, as described below, for 200 barrels per day of crude oil. The Company utilized a "no cost" collar to reduce the effect of price changes on a portion of its future
oil production. 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, they
may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing
derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions.

The
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 derivative contract is
currently with a single counterparty and the Company is a guarantor of Kodiak USA. The Company has netting arrangements with the counterparty that provides for the offset of payables against
receivables from separate derivative arrangements with that counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the
event of default by one of the parties to the agreement.

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

The
Company's commodity derivative contract is summarized below:

Contract Type

Counterparty

Basis

Quantity(Bbl/d)

Strike Price ($/Bbl)

TermCollar

BP North America

NYMEX


200

$
70.00/$90.00


Mar 1 - Dec 31, 2010


The
following table details the fair value of the derivatives recorded in the condensed consolidated balance sheet, by category:

Fair Value atUnderlying Commodity

Location on Balance Sheet

March 31, 2010

December 31, 2009Crude oil derivative contract

Current liability

$
122,230

$



Unrealized
gains and losses resulting from derivatives are recorded at fair value on the balance sheet and changes in fair value are recognized in the unrealized loss on risk management
activities line on the consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management
activities line on the consolidated statement of income. There were no realized gains or losses recorded for the three months ending March 31, 2010.

Fair Value of Financial Instruments

The Company's financial instruments, other than the derivative instrument discussed above, including cash and cash equivalents, 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 March 31, 2010 and
December 31, 2009 were not significant.

Computation of Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted
average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation
of basic net income (loss) per share. Diluted net income per common share includes shares of restricted stock and the potential dilution that could occur upon exercise of the options to acquire common
stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

have
been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting
period).

The
table below sets forth the computations of basic and diluted net income per share for the three months ended March 31, 2010.

Three months ended March 31,2010

2009Numerator:Basic net income

$
980,750

$
(1,627,607
)Dilutive adjustments to net income





Diluted net income

$
980,750

$
(1,627,607
)Denominator:Basic weighted average common shares outstanding


118,931,087


95,129,431Effect of dilutive securitiesOptions to purchase common stock


3,569,896


Assumed treasury shares purchased


(1,912,043
)

Diluted weighted average commons shares outstanding


120,588,940


95,129,431Basic net income per share


0.01


(0.02
)Diluted net income per share


0.01


(0.02
)


For
the three months ended March 31, 2010, 2,782,000 options to purchase common stock were excluded from the diluted weighted average shares outstanding because the exercise of
these options would have been anti-dilutive.

11

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Table of Contents

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 accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation
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 is allocated to operating expense using a systematic and rational method. As of March 31, 2010, and December 31, 2009, the Company has recorded a net asset of $751,988 and
$603,526 and a related liability of $1,261,071 and $1,060,210, respectively. The information below reconciles the value of the asset retirement obligation for the periods presented.

For the Three
Months Ended
March 31, 2010

For the Year Ended
December 31, 2009Balance beginning of period

$
1,060,210

$
787,180Liabilities incurred


110,760


251,671Liabilities settled





(74,078
)Revisions


64,594


Accretion expense


25,507


95,437Balance end of period

$
1,261,071

$
1,060,210


Off Balance Sheet Arrangements

Other than standard operating leases and our drilling rig commitments as described in Note 5 below, the Company did not have any
other off balance sheet financing arrangements at March 31, 2010 and December 31, 2009.

Recently Adopted Accounting Pronouncements

In January 2010, the FASB issued ASU 2010-03,Extractive ActivitiesOil and Gas (Topic
932),to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules. The significant revisions involve revised
definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month average of the first day of the month prices and additional disclosure
requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial
statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to
change prior period presentation to conform to the amendments.

12

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

Note 3Wells in Progress

The following table reflects the net changes in capitalized additions to wells in progress during the three months ended March 31, 2010 and the year ended December 31,
2009, and includes amounts that were capitalized and reclassified to producing wells in the same period

For the Three
Months Ended
March 31, 2010

For the Year Ended
December 31, 2009Beginning balance

$
2,691,107

$
728,093Additions to capital wells in progress costs pending the determination of proved reserves


4,397,858


16,127,748Reclassifications to wells, facilities, and equipment based on the determination of proved reserves to full cost pool


(2,526,809
)

(14,164,734
)Ending balance

$
4,562,156

$
2,691,107


As
of March 31, 2010, wells in progress included four gross (2.1 net) Kodiak-operated and two gross (0.1 net) non-operated wells in the Williston Basin and two gross
(0.5 net) non-operated wells in the Vermillion Basin. All of the Williston Basin Kodiak-operated wells classified as wells-in-progress as of March 31, 2010,
are anticipated to be completed in the second quarter of 2010. The Vermillion Basin wells in progress were drilled in 2008 and 2009 and completion work is anticipated to continue in 2010. The
capitalized costs related to two wells as of December 31, 2009 in the Vermillion Basin were re-classified to the full cost pool in the first quarter of 2010 due to the uncertainty
regarding the ultimate completion of these wells. Because Kodiak's capital costs are largely carried by the operator of this project, this reclassification was minimal.

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,

13

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4Stock-based Compensation Plan (Continued)

subject
to adjustment as defined in the 2007 Plan. The Company granted 885,000 stock options at a stock price of $2.36 per share during the three month period ended March 31, 2010. No options
were granted during the three month period ended March 31, 2009.

Compensation
expense charged against income for all stock-based awards during the three months ended March 31, 2010 and 2009 on a pre-tax basis was approximately
$0.9 million and $0.8 million, respectively, which is included in general and administrative expense in the Condensed Consolidated Statements of Operations.

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

For the Three
Months Ended
March 31, 2010

For the Year Ended
December 31, 2009Risk free rates


2.78 - 3.02
%

1.24 - 1.34
%Dividend yield


0
%

0
%Expected volatility


101.33 - 102.11
%

107.01 - 108.93
%Weighted average expected stock option life


5.95 years


2.97 yearsThe weighted average fair value at the date of grant for stock options granted is as follows:Weighted average fair value per share

$
1.89

$
0.77Total options granted


885,000


1,150,000Total weighted average fair value of options granted

$
1,672,650

$
865,433


A
summary of the stock options outstanding as of March 31, 2010 is as follows:

Number
of Options

Weighted
Average
Exercise
PriceBalance outstanding at December 31, 2008


7,507,499

$
3.25Granted


1,150,000


1.96Canceled


(1,946,999
)

4.40Expired


(775,000
)

0.45Exercised


(350,500
)

0.58Balance outstanding at December 31, 2009


5,585,000

$
2.36Granted


885,000


2.36Canceled


(5,104
)

1.18Expired





Exercised


(113,000
)

1.00Balance outstanding at March 31, 2010


6,351,896

$
2.39Options exercisable at March 31, 2010


4,479,562

$
2.43


14

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4Stock-based Compensation Plan (Continued)

At
March 31, 2010, stock options outstanding were as follows:

Exercise Price

Number of Shares

Weighted Average
Remaining Contractual
Life (Years)$0.36 - $1.00


640,000


8.75$1.01 - $2.00


1,794,896


2.82$2.01 - $3.00


1,235,000


9.02$3.01 - $4.00


2,177,000


3.52$4.01 - $5.00


190,000


1.24$5.01 - $6.26


315,000


7.156,351,896


5.03


The
aggregate intrinsic value of both outstanding and vested options as of March 31, 2010 was $5,289,474 based on the Company's March 31, 2010 closing common stock price of
$3.41 per share. The total grant date fair value of the shares vested during the three months ended March 31, 2010 was $889,299. As of March 31, 2010, there was $1,953,397 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, 2010, there were 23,000 unvested shares of restricted stock grants with a weighted-average grant date fair value of $3.66 per share. Total unrecognized
compensation cost of $43,142 related to non-vested restricted stock is expected to be recognized over an eighteen month period. The Company recognizes compensation cost over the requisite
service period for the entire award. The fair value of restricted stock grants is based on the stock price on the grant date and the Company assumes no annual forfeiture rate.

Note 5Commitments and Contingencies

The Company leases office facilities under an operating lease agreement that expires on June 30, 2012. Rent expense was $63,067 and $60,779 for the three month periods ended
March 31, 2010 and 2009, respectively.

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

Years ending on December 31,2010


219,5092011


303,1712012


154,172Total

$
676,852


During
the second quarter of 2008, the Company entered into contracts for the use of two new-build drilling rigs. The first rig was placed into operation in November 2008 and
entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior to September 15, 2010. The Company is currently utilizing this rig for
drilling in the Williston Basin. The contract can be extended by mutual consent of Kodiak and the drilling contractor at its termination. The estimated

15

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5Commitments and Contingencies (Continued)

termination
fee for this first rig is approximately $3.1 million as of March 31, 2010. The second rig was placed into operation in March 2010 and entails a two-year drilling
commitment or specific termination fees if drilling activity is cancelled prior to March 10, 2012. The Company currently plans to continue utilizing this rig in its drilling operations in the
Williston Basin through the contracted period. The estimated termination fee for the second rig is approximately $5.1 million as of March 31, 2010.

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

Note 6Credit Facility

On September 11, 2008, our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., entered into a two-year, revolving, senior secured credit facility (the
"Credit Facility") with Bank of the West, NA. On September 30, 2008, Kodiak USA, a wholly-owned subsidiary of Kodiak Oil & Gas Corporation Company, entered into an ISDA Master Agreement
(the "Agreement"), with Bank of the West, under which the Company could enter into hedging transactions designed to protect against changes in interest rates, currency exchange rates, and fluctuations
in the price of oil, gas, hydrocarbons or other commodities. The Credit Facility and the ISDA Master Agreement were terminated in March 2010 and the capitalized deferred financing costs of $49,809
related to the institution of the Credit Facility were amortized in the quarter ended March 31, 2010.

Note 7Fair Value Measurements

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



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.

16

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7Fair Value Measurements (Continued)

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, 2010 by level within the
fair value hierarchy:

Fair Value Measurements UsingLevel 1

Level 2

Level 3

TotalAssetsCommodity price risk management asset











Liabilities:Commodity price risk management liability





(122,230
)




(122,230
)


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

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

Note 8Differences Between Canadian and United States Accounting Principles

These financial statements have been prepared in accordance with 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 its financial statements would vary materially had they been prepared in accordance with Canadian GAAP or that any recently issued, not yet effective, Canadian accounting standards if
currently adopted would have a material effect on the accompanying financial statements.

Note 9Subsequent Events

Acquisitions

In April 2010, the Company closed on two separate definitive purchase and sale agreements to acquire additional Williston Basin
leasehold. In the first transaction, Kodiak acquired 5,680 gross mineral acres (4,531 net) in McKenzie County, N.D. The lands are located on the border of McKenzie and Williams Counties, N.D. and
offset existing Bakken and Three Forks producing wells successfully drilled and completed by other operators. The contiguous leasehold position was acquired from a private party. Also included in the
acquisition are certain surface facilities and equipment associated

17

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 9Subsequent Events (Continued)

with
a temporarily abandoned well and pipeline infrastructure that ties into a regional natural gas pipeline controlled by a third-party.

In
the second transaction, the Company acquired an additional 25% working interest in existing properties in its Grizzly Project area in the Mondak Field located on the southeastern end
of the Elm Coulee Field on the Montana/North Dakota border in McKenzie County. Included in the acquisition is the additional working interest in the Company's existing lands that are prospective for
Bakken and Three Forks production, producing properties, and production facilities. The Company anticipates drilling two wells in the Grizzly Project area with operations commencing in the second
quarter 2010.

Grants of officer, director and employee stock options

On April 1, 2010, the Compensation Committee granted to certain officers and employees performance-based stock options to
acquire 552,000 shares under the 2007 Stock Incentive Plan and 448,000 shares under the proposed amended 2007 Stock Incentive Plan, subject to shareholder approval at the Annual Meeting on
June 3, 2010. The vesting of the officers' stock option grants is subject to the corporate performance-based measurements.

On
April 1, 2010, the Compensation Committee granted stock options to acquire 99,000 shares under the 2007 Stock Incentive Plan and 126,000 shares under the proposed amended 2007
Stock Incentive Plan, subject to shareholder approval at the Annual Meeting on June 3, 2010. Each of these grants will vest quarterly beginning June 30, 2010.

18

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Table of Contents

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, 2009. The following
factors, among others, could cause actual results to differ from those set forth in the forward-looking statements:



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.

19

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Table of Contents

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 assets in the Williston Basin of North Dakota and Montana and in the Green River Basin of Wyoming and Colorado.

Williston Basin

The primary geologic target in the Williston Basin is the Bakken and Three Fork Formations. The Basin also produces from many other
Formations including, but not limited to, the Mission Canyon, Nisku, and Red River. We are currently operating a two-rig program in the Williston Basin and anticipate continued operation
throughout 2010 with these rigs. These two rigs are under two-year contracts that expire in the fourth quarter of 2010 and the first quarter of 2012, respectively. In addition, we will be
participating in wells drilled by other operators throughout the Williston Basin.

Bakken and Three Forks oil play in Dunn and Mountrail Counties, N.D:As of March 31, 2010, we owned an interest in
approximately 56,000 gross
(35,000 net) acres in this highly prospective play. Through the first quarter of 2010, we have drilled thirteen and completed eleven wells in this play.

Two
wells, the MC #16-3-11H and MC #16-3H that are Kodiak-operated (60% working interest and 49% net revenue interest) were completed and brought on
to production during the first quarter of 2010. These two wells have each produced crude oil over the first 30-day period at rates nearly 50% better than 30-day rates obtained
on similar length laterals completed in 2009. We believe these results are evidence of the Company's continued improvement in drilling and completion techniques. Kodiak will continue to evaluate these
results and continually seek to achieve optimal long-term economics.

We
anticipate completion of three additional Kodiak operated wells during the second quarter of 2010. These three wells were drilled from a single pad so drilling on all three must be
finished before completion operations can begin. Kodiak's use of pad drilling has proven to reduce costs through fewer locations and the elimination of mobilization time. We currently have ten
drilling pads approved by the Bureau of Indian Affairs, which can accommodate from one to four well bores each.

Kodiak
is currently participating in the drilling of four non-operated wells in Dunn and Mountrail Counties, with working interests ranging from 5% to 8%. We anticipate that
at least one of the wells will be completed during the second quarter of 2010.

In
the first three months of 2010, we incurred capital expenditures of approximately $7.7 million on our Dunn County properties largely related to the drilling and completion
operations. We anticipate total drilling and completion capital expenditures in this area to be approximately $55.0 million for the entire year of 2010.

20

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Table of Contents

Williston Acreage in eastern Montana and western North Dakota:As of March 31, 2010, we owned an interest in approximately
38,000 gross
(23,000 net) acres in Sheridan County, MT and McKenzie County, N D. We recently completed drilling one well and have spud a second well to test the Red River Formation. Completion operations on the
first well should commence in May 2010. While drilling these wells to the Red River Formation we will also be able to evaluate the Bakken and Three Fork Formations in this area.

In
April 2010, we closed on two separate definitive purchase and sale agreements to acquire additional Williston Basin leasehold. In the first transaction, we acquired 5,680 gross
mineral acres (4,531 net) in McKenzie County, N.D. The lands are close to existing Bakken and Three Forks producing wells successfully drilled and completed by other operators. The contiguous
leasehold position was acquired from a private party. Also included in the acquisition are certain surface facilities and equipment associated with a temporarily abandoned well and pipeline
infrastructure that ties into a regional natural gas pipeline controlled by a third-party.

In
the second transaction, we acquired an additional 25% working interest in existing properties in our Grizzly Project area in the Mondak Field located on the southeastern end of the
Elm Coulee Field on the Montana/North Dakota border in McKenzie County, N.D. Included in the acquisition is the additional working interest in our existing lands that are prospective for Bakken and
Three Forks production, producing properties, and production facilities. The Company anticipates drilling two wells in the Grizzly Project area with operations commencing in the second quarter 2010.

Kodiak
anticipates the commencement of drilling operations on two wells in the Grizzly prospect area during the second quarter of 2010. It is also anticipated that Kodiak will
participate in a non-operated well in this same area.

Green River Basin / Vermillion Basin

Vermillion Basin of southwest Wyoming:As of March 31, 2010, we owned an interest in approximately 41,000 gross (8,900 net) acres
in the
Vermillion Basin. In mid 2010 we anticipate that the operator of this prospect will re-enter a well that was vertically drilled in 2008 to the top of the Baxter Shale and horizontally
drill to evaluate the potential of the Baxter Shale interval. The Company has not allocated significant capital to this project as it expects to be carried for these expenditures under its current
contract with its partner.

21

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Table of Contents

The following summary provides a tabular presentation of data pertinent to Kodiak's drilling and completions activities in the first half of 2010 as of April 15,
2010:

Kodiak Oil & Gas Corp. Drilling and Completion Activities  Longer Laterals (8,000 to 10,000)

Well

WI / NRI
(%)

Length of
Lateral

Completion
Date

Number
of Stages

IP 24-Hour
Test BOE/D

First 30 Day
BOE
Production

StatusMC #13-34-28-2H

57.5 /46.5


9,769

Q210


15







Waiting completionMC #13-34-28-1H

57.5 /46.5


8,695

Q210










Waiting completionTSB #14-21-33-16H

50 /41















Spud in 2Q 2010TSB #14-21-33-15H

50 /41















Spud in 2Q 2010TSB #14-21-16-2H

50 /41















Spud in 2Q 2010Shorter Laterals (4,000 to 7,000)MC #16-3-11H

60 /49


4,729

2/12/2010


12


1,419


22,275

Flowing wellMC #16-3H

60 /49


4,188

3/2/2010


10


1,495


19,061

Flowing wellMC #13-34-3H

60 /49


4,330

Q210


11







Waiting completionTSB #14-21-4H

50 /41


4,500
*











Spud in 2Q 2010Wells outside FBIR BoundaryMeagher 16-30

33.5 /27




Q210










Waiting completionHarshbarger 13-20-29

43 /34















DrillingGrizzly 13-6-R

100 /82.5















Spud after Harshbarger


*Expected
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 have limited commodity price hedges in place.

The
Company's oil and gas sales volumes are directly related to the results of its exploratory and acquisition activities. Production volumes may vary monthly as various wells are
completed or maintained in an effort to provide optimal production. Sales volumes, prices received and production

22

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Table of Contents

costs
are summarized in the following table for the three month periods ended March 31, 2010 and March 31, 2009.

For the three months endedMarch 31, 2010

March 31, 2009Sales Volume:Gas (Mcf)


43,077


99,694Oil (Bbls)


77,205


16,486Production volumes (BOE)


84,385


33,101Price:Gas ($/Mcf)

$
5.41

$
2.83Oil ($/Bbls)

$
71.08

$
30.04Production costs ($/BOE):Lease operating expenses

$
6.53

$
4.15Production and property taxes

$
7.82

$
(0.80
)Gathering, Transportation & & Marketing

$
0.14

$
1.14


Results of Operations

For the Three Months Ended March 31, 2010 compared to the Three Months Ended March 31, 2009

The Company reported net income for the three months ended March 31, 2010 of approximately $981 thousand compared to a
net loss of $1.6 million for the same period in 2009. The improvement from a net loss to net income is attributable to the new production from our Bakken wells, which began producing in the
second quarter of 2009, and includes sales from two recently completed Bakken wells which came on to production in the first quarter of 2010. For the three months ending March 31, 2010, our
volumes on a BOE basis increased 155% from 33,102 BOE in the first quarter of 2009 to 84,385 BOE during the first quarter of 2010. In addition, we also realized increased prices for both oil and
natural gas during the three month period ended March 31, 2010 versus the three month period ended March 31, 2009. Oil price realizations increased by 137% to $71.08 per barrel for the
three month period ended March 31, 2010, compared to $30.04 per barrel for the same period in 2009. Total natural gas price realizations increased 91% to $5.41 per Mcf for the three month
period ended March 31, 2010, compared to $2.83 per Mcf for the same period in 2009. Our increased oil production and, to a lesser extent, the increased pricing received for our products for the
period resulted in an increase in oil and gas revenue of $4.9 million, from approximately $778,000 to $5.7 million, a 636%

23

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Table of Contents

increase
in revenue for the three month period ended March 31, 2010 compared to the same period in 2009.

For the three months endedMarch 31, 2010

March 31, 2009Financial ResultsTotal revenue

$
5,608,919

$
791,360Total costs and expenses

$
4,628,169


2,418,967Net income (loss)

$
980,750

$
(1,627,607
)Basic and diluted net income (loss) per common share

$
0.01

$
(0.02
)Capital Resources and LiquidityCash and cash equivalents at end of the period

$
10,567,026

$
2,007,423Net cash (used in) operating activities

$
(2,406,660
)
$
(2,473,391
)Capital expendituresoil and gas properties excluding accruals and proceeds from divestitures

$
7,446,700

$
3,817,427Adjusted EBITDA (see below discussion)

$
3,277,215

$
(491,731
)


Oil and Gas Revenue and Production

During the three month period ended March 31, 2010, as compared to the same period in 2009, crude oil production volumes
increased 368% due to new production from completion operations on our FBIR area. Natural gas production volumes decreased 57% due to our decision to limit production on our Wyoming wells and natural
declines in other gas well production. Oil and natural gas revenues increased by $4.9 million or 636% compared to the first quarter of 2009, primarily due to our increased volumes attributable
to our recent well completions and, to a lesser extent, increased realized pricing for oil and natural gas in 2010 versus 2009. The increase in oil and gas revenue was 70% attributable to the increase
in production volumes and 30% attributable to the increase in realized commodity prices.

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of approximately $1.2 million during the three month
period ended March 31, 2010, as compared to $149 thousand during the same period in 2009. The increase is due to our increased lease operating expenses on the eleven new wells on
production as of March 31, 2010 that were not in production in 2009 and the related severance taxes paid related to the revenue received on the new wells production.

Depletion, Depreciation and Amortization

Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was approximately $1.3 million, for the
three month period ended March 31, 2010, compared to $355 thousand for the same period in 2009. DD&A expense increased during the quarter due to increased production for the new wells
placed in service from the second quarter of 2009 through the first quarter of 2010.

Ceiling Test Impairment

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income
taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to
amortization (without regard to estimates of fair value), or estimated fair value, if lower of unproved properties that are subject to amortization. For the three months ended March 31, 2010,
and March 31, 2009, respectively, no impairment charges were recorded.

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General and Administrative Expense

The Company's general and administrative costs were approximately $2.1 million for the three months ended March 31, 2010
compared to approximately $1.9 million for the same period in 2009. This 9% increase for the period is primarily due to adding additional employees in 2010. Excluding the non-cash
stock-based compensation expense in each period, our general and administrative expenses increased by approximately $97 thousand or 9% during the three month period ended March 31, 2010
as compared to the same period in 2009. This increase is also primarily attributed to adding additional employees in 2010. Our stock- based compensation expense, related to options and restricted
stock issued to officers, directors and employees, of approximately $854 thousand was recorded for the three months ended March 31, 2010. The expense was equivalent to the approximate
$781 thousand stock-based compensation expense recorded for the same period in 2009.

EBITDA

In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gains or losses 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, future capital expenditures and servicing of borrowings under a potential future credit facility as described in
more detail below under the heading "Liquidity and Capital Resources". The Company's Adjusted EBITDA increased by approximately $3.8 million to approximately $3.3 million for the three
months ended March 31, 2010 as compared to the same period in 2009. The increase in Adjusted EBITDA was the result of the increase in both oil and natural gas production due to our successful
drilling and completion operations during the period as compared to the same period in 2009 and, to a lesser extent, due to the increase in realized prices received for both oil and natural gas
production in the first quarter of 2010 versus the first quarter of 2009. 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 March 31, 2010 and 2009 is provided in the table below:

Three months ended
March 31, 2010

Three months ended
March 31, 2009Reconciliation of Adjusted EBITDA:Net income (loss)

$
980,750

$
(1,627,607
)Add back:Depreciation, depletion, amortization and accretion


1,320,605


355,340(Gain) / loss on foreign currency exchange


(913
)

(853
)Unrealized (gain) / loss on commodity price risk management activities


122,230


Stock based compensation expense


854,543


781,389Adjusted EBITDA

$
3,277,215

$
(491,731
)


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Liquidity and Capital Resources

The following table sets forth our liquidity and capital resources as of and for the three months ended March 31, 2010 and 2009:

For the three months ended
March 31,2010

2009Capital Resources and LiquidityCash and cash equivalents at end of the period

$
10,567,026

$
2,007,423Net cash (used in) operating activities


(2,406,660
)

(2,473,391
)Net cash used in investing activities


(12,024,540
)

(3,100,451
)Net cash provided by financing activities


112,680


Net cash flow


(14,318,520
)

(5,573,842
)


Kodiak
ended the first quarter of 2010 with total working capital of approximately $23.6 million, which included cash and cash equivalents of approximately $10.6 million as
compared to working capital of approximately $28.3 million, which included cash and cash equivalents of approximately $24.9 million at year-end 2009. As operator of our
current activity in the Williston Basin we must place orders and take delivery of tubular goods in advance of actual drilling in order to assure availability of the tubular goods. With the addition of
a second drilling rig in the first quarter of 2010 and the current level of drilling activity and requirements for tubular goods, the Company placed orders on tubular goods for its 2010 drilling
program in the first quarter of 2010. As wells are drilled these tubular goods become part of our cost of wells, whereby our working interest share is already paid while the portion related to other
working interest partners is recovered through our joint interest billings. As of March 31, 2010, we had prepaid $10.8 million towards the cost of tubular goods ($8.4 million of
tubular goods that are inventoried in third party yards and $2.4 million of deposits for tubular goods that will be delivered later this year), compared to $7.3 million at
December 31, 2009. With respect to the increase in prepaid tubular goods of $3.5 million from December 31, 2009 to March 31, 2010, approximately $2.0 million of
prepaid tubular goods were used in operations ($1.2 million billed to working interest partners) and we took delivery of an additional $3.1million of tubular goods. The Company placed an order
for its 2010 drilling program resulting in a $2.4 million deposit balance. Net cash flow used in operating activities for the three months ended March 31, 2010 was $2.4 million.
Net cash used as
investing activities (which includes recoupments from partners and restricted cash changes) totaled $12.0 million for the three months ended March 31, 2010. These investing items were
comprised of $8.0 million for oil and gas capital investments on an accrued accounting basis and then adjusted for oil and gas properties sold, prepaid tubular goods, expense accruals, and
asset retirement obligations, resulting in a cash basis oil and gas capital investment of $7.4 million the three months ended March 31, 2010.

Our
results of operations and financial condition are significantly affected by the success of our exploration and land leasing activity, the resulting production and reserves, oil and
natural gas commodity prices and the costs related to operating our properties. In the three months ended March 31, 2010, our oil and natural gas revenue increase by 636% from
$778 thousand as of March 31, 2009 to $5.7 million as of March 31, 2010. This increase is largely the result of the increase in our crude oil production in 2010 compared to
2009 along with improved prices realized for our oil and natural gas production. Total costs and expenses increased to $4.6 million for the three months ended March 31, 2010 from
$2.4 million for same period of 2009. This increase is primarily due to our increased lease operating expense resulting from adding eleven wells to production from March 31, 2009 to
March 31, 2010, the related severance taxes paid on production from the wells added and the increase in depletion due to the same wells added to our production base.

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During
the first three months of 2010, we incurred capital expenditures of approximately $8.0 million. We continue to evaluate and monitor our capital expenditures in relation to
commodity prices. As oil prices have improved since the beginning of the year and from year over year, we have continued to drill and complete wells in the Williston Basin. As mentioned above, in
March 2010, we took delivery of a second drilling rig which we are currently using in drilling operations in the Williston Basin. At this time we anticipate that we will continue to operate two
drilling rigs and our capital expenditures for the year are expected to be approximately $60.0 million excluding acquisitions. Such estimate does not include any potential costs or fees
associated with the termination of either drill rig.

The
following tables set forth our capital expenditures for the three months ended March 31, 2010, and our budgeted capital expenditures for 2010 for our principal properties. Net
capital expenditures include both cash expenditures and accrued expenditures and are net of proceeds from divestitures. For details regarding the Company's 2010 Capital Budget, please refer to our
Annual Report on Form 10-K, filed March 11, 2010.

Project Location

2010 Net Capital
Expenditures(1)
($000)

2010 Budgeted
Net Capital
Expenditures
($000)Williston BasinMission Canyon/Red River wells and related infrastructure


249


1,122Bakken wells and related infrastructure


7,185


57,100Acreage/Seismic


511


2,000Total Williston Basin

$
7,945

$
60,222WyomingVermillion Basin wells and related infrastructure

$
17

$
Acreage/Seismic


15


Total Wyoming

$
32

$
Total All Areas

$
7,977

$
60,222


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


The
2010 capital expenditure budget, both as to amount and allocation, is subject to market conditions, oilfield services and equipment availability, commodity prices and drilling
results. While we continue to explore opportunities to expand our acreage position, our current budget is primarily allocated to drilling and completing wells. If we identify acreage that meets our
strategic requirements, we may re-allocate our capital expenditure budget to permit us to complete a potential acreage acquisition. Alternatively, depending on the availability and terms
of capital resources that may be available to us, we may increase our capital expenditure budget to allow us to acquire additional acreage. We expect to fund our capital budget primarily from cash on
hand, anticipated cash flow from operations and borrowings under a potential reserve-based revolving line of credit as described in more detail below. As of March 31, 2010, our remaining
capital budget of approximately $53 million is significantly more than our working capital of approximately $24 million and to date we have not had positive cash flow from operations. If
our existing and potential sources of liquidity are not sufficient to undertake our planned or revised capital expenditures, we may alter our drilling program, pursue joint ventures with third
parties, sell interest in one or more of our properties or sell common shares. There can be no assurance that any such transactions can be completed or that such transactions will satisfy our
operating capital requirements. If we are not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required

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to
curtail our planned expenditures or restructure our operations, and we would be unable to implement our original exploration and drilling program.

During
the second quarter of 2010, after discussions with several financial institutions regarding the establishment of a reserve-based revolving line of credit, we have begun the
process to enter into a line of credit with a large commercial bank. Although preliminary indications are encouraging, we cannot give assurance that a credit facility will be available to us on terms
acceptable to us, or at all. If we borrow funds under a new credit agreement, we will be obligated to make periodic interest or other debt service payments and may be subject to additional restrictive
covenants. The ability to borrow funds is dependent on a number of variables, including our proved reserves, and assumptions regarding the price at which oil and natural gas can be sold.

Oil and Gas Properties

As of March 31, 2010, we had several hundred lease agreements representing approximately 154,000 gross and 82,000 net acres,
primarily in the Green River and Williston Basins.

As
of March 31, 2010, we had an interest in approximately 56,000 gross acres and 35,000 net acres in the Bakken oil play located on the FBIR in Mountrail and Dunn Counties, N.D.
The majority of our lands in this area are administered by the Bureau of Indian Affairs on behalf of the individual members of the Three Affiliated Tribes of the Fort Berthold Indian Reservation.
Typically, these lands are acquired through a private negotiation with the individual land owners or the Three Affiliated Tribes and have a primary lease term of five years. The land owner typically
retains an 18% landowner royalty. In most cases, these lands require an annual delay rental of $2.50 per net acre.

As
of March 31, 2010, we owned an interest in approximately 38,000 gross 23,000 net acres in the Williston Basin outside the FBIR in Sheridan County, MT, and McKenzie and Divide
Counties, N.D. This acreage is prospective for Mission Canyon, Red River, Bakken and Three Forks formations. We have drilled one of our two anticipated wells to test the Red River formation where we
will have the opportunity to evaluate the Bakken and Three Fork formations.

Our
leasehold interests in the Vermillion Basin total approximately 41,000 gross and 8,900 net acres as of March 31, 2010.

The
following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of March 31, 2010.

Undeveloped
Acreage(1)

Developed
Acreage(2)

Total AcreageGross

Net

Gross

Net

Gross

NetGreen River BasinWyoming


38,854


8,915


1,520


908


40,374


9,823Colorado


7,339


4,960


0


0


7,339


4,960Williston BasinMontana


25,984


15,968


800


400


26,784


16,368North Dakota


59,007


36,498


8,160


4,395


67,167


40,893Other BasinsWyoming


12,042


10,355


0


0


12,042


10,355Acreage Totals(3)


143,226


76,696


10,480


5,703


153,706


82,399


(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.


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(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.


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

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

Expiring AcreageYear Ending

Gross

NetDecember 31, 2010


16,857


16,519December 31, 2011


6,580


3,682December 31, 2012


31,633


19,093December 31, 2013


19,649


11,467Total


74,719


50,761


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

Commitments and Contingencies

During the second quarter of 2008, the Company entered into contracts for the use of two new-build drilling rigs. The first
rig was placed into operation in November 2008 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior to September 15, 2010.
The Company intends to continue to utilize this rig in its drilling operations in the Williston Basin. The estimated termination fee for the first rig is approximately $3.1 million as of
March 31, 2010. The second rig was placed into operation in March 2010 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled
prior to March 10, 2012. The Company intends to continue to utilize this rig in its expanding drilling operations in the Williston Basin. The estimated termination fee for the second rig is
approximately $5.1 million as of March 31, 2010.

For
a further discussion of our commitments and contingencies, see Note 5 to our financial statements included above, which is incorporated herein by reference.

Off Balance Sheet Arrangements

Other than standard operating leases and our drilling rig commitments, as amended, the Company did not have any other off balance sheet
financing arrangements at March 31, 2010 and December 31, 2009.

Critical Accounting Policies and Estimates

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

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Recently Issued Accounting Pronouncements

In January 2010, the FASB issued ASU 2010-03,Extractive ActivitiesOil and Gas (Topic
932),to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules. The significant revisions involve revised
definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month average of the first day of the month prices and additional disclosure
requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial
statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to
change prior period presentation to conform to the amendments.

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

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 an approximate $42,882 change in our gross gas production revenue based on our
production volumes for the three months ended March 31, 2010. A $1.00 per barrel change in the market price of oil will result in an
approximate $77,225 change in our gross oil production revenue based on our production volumes for the three months ended March 31, 2010.

Interest Rate Fluctuations

We currently maintain a portion of our available cash in redeemable short term investments, classified as cash equivalents, and our
reported interest income from these short term investments could be adversely affected by any material changes in US dollar interest rates. A 1% change in the interest rate would have approximately a
$164,420 annual impact if all of our cash, as of March 31, 2010, was invested in interest bearing notes.

ITEM 4.    CONTROLS AND PROCEDURES

Under the supervision and with the participation of our management, we evaluated the effectiveness of our disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the "Exchange Act") as of March 31, 2010. On the basis of this
review, our management concluded that our disclosure controls and procedures are effective to give reasonable assurance that the information we are required to disclose in reports that we file or
submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be
disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner
that allows timely decisions regarding required disclosure.

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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, 2009, as filed with the SEC on March 12, 2009. The risk factors disclosed here and in our Annual Report on
Form 10-K for the fiscal year ended December 31, 2009, 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 may incur termination fees related to two drilling rig contracts that we entered into in 2008 which could impair our working capital.

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. The estimated
termination fee for the first rig is approximately $3.1 million as of March 31, 2010. 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, we entered into an addendum to the Second Rig Contract to defer such delivery. Pursuant to the addendum, we agreed to make monthly Delay
Payments until the earlier of delivery of the second rig or the expiration of twelve months. In the first quarter of 2010, we took delivery of the second rig; therefore, we have discontinued payment
of the Delay Payments, and the contractual portion of past Delay Payments will be applied as a credit against rig operating rates. In the event that the Company cancels the Second Rig Contract after
delivery, the Company may be required to pay a termination fee. At March 31, 2010, the maximum termination fee payable by the Company would be $5.1 million, against which any Delay
Payments not previously applied as a credit against rig operating rates would be applied as a credit. If we were to incur these fees by terminating the drilling rigs, our working capital could be
impaired, which would accelerate the need we may have for additional capital funding.

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

Exhibit Number

Description10.1

Officer Position Termination and General Release Agreement between the Company and James K. Doss, effective March 18, 2010.31.1

Certification of the Principal Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 200231.2

Certification of the Principal Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 200232.1

Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 135032.2

Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350


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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.

KODIAK OIL & GAS CORP.May 6, 2010

/s/ LYNN A. PETERSON Lynn A. Peterson President and Chief Executive OfficerMay 6, 2010

/s/ JAMES P. HENDERSON James P. Henderson Chief Financial Officer
(principal financial officer)


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