Table of Contents



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, 2009

Commission File No. 001-32920

GRAPHIC

(Exact
name of registrant as specified in its charter)

Yukon Territory(State or other jurisdiction
of incorporation or organization)

N/A(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 the 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

95,129,431 shares, no par value, of the Registrant's Common Stock were issued and outstanding as of May 7, 2009.



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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

18ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

30ITEM 4.

CONTROLS AND PROCEDURES

30PART IIOTHER INFORMATION

31ITEM 1.

LEGAL PROCEEDINGS

31ITEM 1A.

RISK FACTORS

31ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

32ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

32ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

33ITEM 5.

OTHER INFORMATION

33ITEM 6.

EXHIBITS

33SIGNATURES

34


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PART 1FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)
March 31,
2009

(Audited)
December 31,
2008ASSETSCurrent Assets:Cash and cash equivalents

$
2,007,423

$
7,581,265Accounts receivableTrade


4,018,063


1,934,818Accrued sales revenues


757,962


516,870Prepaid expenses and other


8,903,613


10,621,980Total Current Assets


15,687,061


20,654,933Oil and gas properties (full cost method), at cost:Proved oil and gas properties


99,267,199


97,934,058Unproved oil and gas properties


12,049,766


11,985,533Wells in progress


3,730,114


728,093Less-accumulated depletion, depreciation, amortization, accretion and asset impairment


(93,102,757
)

(92,804,911
)Net oil and gas properties


21,944,322


17,842,773Other property and equipment, net of accumulated depreciation of $299,402 in 2009 and $270,620 in 2008


240,722


272,705Restricted investments





246,068Total Assets

$
37,872,105

$
39,016,479LIABILITIES AND STOCKHOLDERS' EQUITYCurrent Liabilities:Accounts payable and accrued liabilities

$
2,682,673

$
4,125,335Advances from joint interest owners


2,150,020


1,105,740Total Current Liabilities


4,832,693


5,231,075Noncurrent Liabilities:Asset retirement obligation


887,405


787,180Total Liabilities


5,720,098


6,018,255Commitments and ContingenciesNote 5Stockholders' Equity:Common stockno par value; unlimited authorizedIssued and outstanding: 95,129,431 shares in 2009 and95,129,431 shares in 2008Contributed surplus


137,079,234


136,297,845Accumulated deficit


(104,927,227
)

(103,299,621
)Total Stockholders' Equity


32,152,007


32,998,224Total Liabilities and Stockholders' Equity

$
37,872,105

$
39,016,479


SEE
ACCOMPANYING NOTES

2

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

For the Three Months Ended
March 31,2009

2008Revenues:Gas production

$
282,474

$
465,865Oil production


495,259


1,412,306Interest


13,627


83,366Total revenue


791,360


1,961,537Cost and expenses:Oil and gas production


148,529


982,951Depletion, depreciation, amortization and accretion


355,340


1,097,299General and administrative


1,915,951


2,495,042(Gain)/loss on currency exchange


(853
)

18,281Total costs and expenses


2,418,967


4,593,573Net loss

$
(1,627,607
)
$
(2,632,036
)Basic & diluted weighted-average common shares outstanding


95,129,431


87,992,931Basic & diluted net loss per common share

$
(0.02
)
$
(0.03
)


SEE
ACCOMPANYING NOTES

3

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

Three Months Ended
March 31,2009

2008Cash flows from operating activities:Net loss

$
(1,627,607
)
$
(2,632,036
)Reconciliation of net loss to net cash (used in) provided by operating activities:Depletion, depreciation, amortization and accretion


355,340


1,097,299Stock based compensation


781,389


1,518,810Changes in current assets and liabilities:Accounts receivable-trade


(2,083,245
)

274,800Accounts receivable-accrued sales revenue


(241,092
)

(9,958
)Prepaid expenses and other


380,077


60,350Accounts payable and accrued liabilities


(38,253
)

(2,738,207
)Net cash (used in)/provided by operating activities


(2,473,391
)

(2,428,942
)Cash flows from investing activities:Oil and gas properties


(3,817,427
)

(3,128,461
)Sale of oil and gas properties





2,437,892Equipment





11,416Prepaid tubular goods


467,704


Restricted investment: undesignated as restricted


249,272


(3,204
)Net cash (used in) investing activities


(3,100,451
)

(682,357
)Net cash provided by financing activities





Net change in cash and cash equivalents


(5,573,842
)

(3,111,299
)Cash and cash equivalents at beginning of the period


7,581,265


13,015,318Cash and cash equivalents at end of the period

$
2,007,423

$
9,904,019Supplemental cash flow informationOil & gas property accrual included in Accounts payable and accrued liabilities

$
1,097,060

$
1,095,418Asset retirement obligation

$
71,514

$
(65,143
)


SEE
ACCOMPANYING NOTES

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

The
Company was incorporated (continued) in the Yukon Territory, 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. 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

On May 6, 2009, the Company entered into agreements to issue 10.0 million shares of our common stock to certain
institutional investors and insiders, including management, in a non-brokered registered direct offering ("Proposed Financing") (see Note 8). If the Proposed Financing closes as
expected on or about May 11, 2009, we anticipate that our resulting net proceeds of approximately $7.45 million, together with our projected 2009 cash flows from operations and our
prepaid tubular goods and surface equipment, would be sufficient to support our planned capital expenditure program through December 2009. If the Proposed Financing were not to close, or if we realize
lower than expected cash flows from operations, either due to lower than anticipated production or lower commodity prices, it will be necessary for the Company to complete an alternate arrangement in
order to fund the Company's 2009 capital expenditures. Specifically, the Company would need to complete one or a combination of the following alternatives, whichever option(s) is (are) in the best
interests of the Company and its shareholders:



The
Company's ability to fund its operations in future periods will depend upon its future operating performance, and more broadly, on the availability of equity and debt financing or
the Company's ability to sell interests in its existing acreage. The Company's ability to succeed in any of

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

these
capital-raising activities will be affected by prevailing economic conditions in its industry and financial, business and other factors, some of which are beyond the Company's control. The
Company cannot be certain that additional funding will be available on acceptable terms, or at all, particularly in light of the current widespread economic downturn. If we are unable to raise
additional capital when required or on acceptable terms, the Company may have to significantly delay, scale back or discontinue its drilling or exploration program, seek to enter into additional joint
venture arrangements with third parties, or seek to sell one or more of its properties.

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, 2008. 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, 2008.

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.

As
of March 31, 2009, the Company had approximately $1.0 million in a money market account with its bank. The money market account is limited to six withdrawals per month;
however, there are no other redemption restrictions. Therefore, the Company classified the entire balance as Cash and Cash Equivalents at March 31, 2009.

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, 2009 and December 31, 2008, we had approximately $8.3 million (consisting of $5.8 million of tubular goods and surface equipment that are
inventoried in third party yards and $2.5 million of deposits for tubular goods that will be delivered later this year) and $9.7 million respectively, of deposits recorded. In respect of
the

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

$2.5 million
tubular goods deposit, the Company estimates that an additional $3.9 million will be paid to complete the purchase. The cost basis of the tubular goods is depreciated as a
component of oil and gas properties once the inventory is used in drilling operations. The $2.5 million deposit is non-refundable if the Company does not complete the additional
$3.9 million purchase. The Company records tubular goods inventory at the lower of cost or market value. As of March 31, 2009, 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. As of December 31, 2008, the market value of the Company's tubular goods inventory
approximated the cost basis.

Restricted Investment

The restricted investments are no longer used as security for our outstanding letters of credit. The investments are short term
certificates of deposits, the balance as of March 31, 2009 was classified as a short term investment. The Company's credit facility (see Note 6) is now used as security for our currently
outstanding letters of credit. However, as a result of the Company's present failure to satisfy one of the financial covenants under the Credit Facility, Bank of the West's obligation to make advances
or issue new letters of credit under the Credit Facility is currently suspended (see Note 6).

Concentration of Credit Risk

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

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

Oil and Gas Producing Activities

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

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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, 2009 and 2008 no unproved land costs were reclassified to proved property and included in the ceiling test and depletion calculations.

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

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

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

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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, 2009 or 2008, respectively. However, during the last half of 2008, oil and natural gas
prices decreased significantly from the record highs seen during the summer of 2008. Natural gas prices in the Rocky Mountains decreased significantly due to the reduction in take-away
capacity caused by pipeline maintenance and repairs during the fall of 2008. The Company recorded a downward reserve revision of approximately 833,800 barrels of oil equivalent (BOE) that included the
removal of four wells with approximately 348,000 BOE from its proved undeveloped (PUD) category of its reserve base. The removal of these PUDs from the reserve base was due to one well that became
uneconomic based on 2008 pricing and anticipated capital requirements related to the well and three wells that the Company removed from its drilling plans. After taking into account the decreases in
the reserve base due to the above factors and the decreases in prices, an impairment expense of $47.5 million was recorded for the year ended 2008.

Wells in Progress

Wells in progress at March 31, 2009 and December 31, 2008 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 are then
transferred to proved property when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods.

Impairment of Long-lived Assets

The Company's unproved properties are evaluated quarterly for the possibility of impairment. In the three months ended March 31,
2009 and 2008, 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 Facility,
which are being amortized over the two year term of the Credit Facility (see Note 6). The Company recorded amortization expense of $6,372 in the three month period ended March 31, 2009.

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

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

property
and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Fair Value of Financial Instruments

The Company's financial instruments, including cash and cash equivalents, 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, 2009 and December 31, 2008 were not significant.

Asset Retirement Obligation

The Company follows SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires that the fair value of a
liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are
capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included
in proved oil and gas properties in the condensed consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with
settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated
dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are also
included in the ceiling test calculation. The asset retirement liability is allocated to operating expense using a systematic and rational method. As of March 31, 2009, and December 31,
2008, the Company has recorded a net asset of $555,849 and $501,900 and a related liability of $887,405 and $787,180, respectively. The information below reconciles the value of the asset retirement
obligation for the periods presented.

For the Period EndedMarch 31, 2009

December 31, 2008Balance beginning of period

$
787,180

$
874,498Liabilities incurred


71,514


Liabilities settled





(147,252
)Accretion expense


28,711


59,934Balance end of period

$
887,405

$
787,180


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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)

Off Balance Sheet Arrangements

Other than standard operating leases and our drilling rig commitments, the Company did not have any off-balance sheet
financing arrangements at March 31, 2009 and December 31, 2008.

Recently Adopted Accounting Pronouncements

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

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

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

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

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

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

recognized
intangible asset under FAS 142, "Goodwill and Other Intangible Assets." FSP FAS 142-3 also requires expanded disclosure related to the determination of intangible
asset useful lives. FSP FAS 142-3 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not permitted. The adoption of FSP
FAS 142-3 did not have a material impact on the Company's financial position or results of operations.

In
June 2008, the FASB issued FSP No. EITF 03-6-1, "Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating
Securities," (FSP EITF 03-6-1). FSP EITF 03-6-1 states that unvested share-based payment awards that contain non-forfeitable
rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the
computation of earnings per share pursuant to the two-class method. FSP EITF 03-6-1 becomes effective for the Company on January 1, 2009. The adoption
of FSP EITF 03-6-1 did not have a material impact on the Company's financial position or results of operations.

Recently Issued Accounting Pronouncements

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162,The Hierarchy of
Generally Accepted Accounting Principles("SFAS 162"). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to
be used in the preparation of financial statements that are presented in conformity with U.S. generally accepted accounting principles. The Statement becomes effective 60 days following the
SEC's approval of the Public Company Accounting Oversight Board amendments to the auditing literature. The adoption of SFAS 162 will not have a material impact on the Company's financial
position, results of operations or cash flows.

On
December 12, 2007, the SEC published a Concept Release on possible revisions to the disclosure requirements relating to oil and gas reserves as specified in
Rule 4-10 of Regulation S-X and Item 102 of regulation S-K. On December 31, 2008, the SEC adopted a final rule that amends its
oil and gas reporting requirements. The revised rules change the way oil and gas companies report their reserves in the financial statements. Definitions were updated to be consistent with Petroleum
Resource Management System (PRMS). Other key revisions include a change in pricing used to prepare reserve estimates, the inclusion of non-traditional resources in reserves, the allowance
for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and other new disclosures. The revised rules are effective for registration statements filed
on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending December 31, 2009, and after. The SEC is precluding
application of the new rules in quarterly reports prior to the first annual report in which the revised disclosures are required. Early adoption is not permitted. The changes are considered a change
in accounting principle that is inseparable from a change in accounting estimate pursuant toFASB Statement No. 154, Accounting Changes and Error
Corrections, and should be accounted for prospectively. Management is evaluating the impact of the adoption of this final SEC ruling on disclosure requirements relating to our
oil and gas reserves and does not anticipate that the implementation of the new reporting requirements will have a material impact on the consolidated results of operations, financial position or
liquidity.

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2009 and the year ended December 31,
2008, and does not include amounts that were capitalized and reclassified to producing wells in the same period.

For the Three
Months Ended
March 31,
2009

For the Year Ended
December 31,
2008Beginning balance

$
728,093

$
414,074Additions to capital wells in progress costs pending the determination of proved reserves


3,952,372


728,093Reclassifications to wells, facilities, and equipment based on the determination of proved reserves to full cost pool


(950,351
)

(414,074
)Ending balance

$
3,730,114

$
728,093


Note 4Stock-based Compensation Plan

In 2007, the Company adopted the 2007 Stock Incentive Plan (the "2007 Plan"), which replaced the Incentive Share Option Plan (the "Pre-existing Plan"). The 2007 Plan
authorizes the Company to issue stock options, stock appreciation rights (SARs), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based
awards to any employee, consultant, independent contractor, director or officer of the Company. A total of 8,000,000 shares of common stock may be issued under the 2007 Plan, which includes shares
issuable under the Pre-existing Plan pursuant to options outstanding as of the effective date of the 2007 Plan. No more than 8,000,000 shares may be used for stock issued pursuant to
incentive stock options and the number of shares available for granting restricted stock and restricted stock units shall not exceed 1,000,000, subject to adjustment as defined in the 2007 Plan. The
Company did not grant any stock options during the three month period ended March 31, 2009. The Company granted 965,000 stock options during the three month period ended March 31, 2008.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4Stock-based Compensation Plan (Continued)

Compensation expense charged against income for all stock-based awards during the three months ended March 31, 2009 and 2008on a pre-tax basis was approximately
$0.8 million and $1.5 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 model to calculate the stock-based compensation expense for the periods presented:

For the Periods EndedMarch 31, 2009

December 31, 2008Risk free rates


1.60 - 4.47
%*

1.60 - 4.53
%Dividend yield


0
%

0
%Expected volatility


56.31 - 104.22
%

54.37 - 104.22
%Weighted average expected stock option life


5.92 years


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


N/A

$
1.08Total options granted





2,296,000Total weighted average fair value of options granted

$


$
2,147,541






A
summary of the stock options outstanding as of March 31, 2009 is as follows:

Number
of Options

Weighted
Average
Exercise
PriceBalance outstanding at December 31, 2008


7,507,499

$
2.87Granted





Canceled


(720,666
)

2.30Expired


(775,000
)

0.45Balance outstanding at March 31, 2009


6,011,833

$
3.25Options exercisable at March 31, 2009


3,949,500

$
3.34


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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, 2009, stock options outstanding were as follows:

Exercise Price

Number of
Shares

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


930,500


7.23$1.01-$2.00


850,000


1.54$2.01-$3.00


350,000


8.07$3.01-$4.00


2,226,333


4.53$4.01-$5.00


190,000


2.24$5.01-$6.26


1,465,000


8.156,011,833


5.54


The
aggregate intrinsic value of both outstanding and vested options as of March 31, 2009 was $0 based on the Company's March 31, 2009 closing common stock price of $0.36
per share. The total grant date fair value of the shares vested during the three months ended March 31, 2009 was $985,453. As of March 31, 2009, there was $2,845,269 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, 2009, there were 48,000 unvested shares of restricted stock grants with a weighted-average grant date fair value of $4.21 per share. Total unrecognized
compensation cost of $107,622 related to non-vested restricted stock is expected to be recognized over a three-year period. The Company recognizes compensation cost over the
requisite service period for the entire award. The fair value of restricted stock grants is based on the stock price on the grant date and the Company assumes no annual forfeiture rate.

Note 5Commitments and Contingencies

The Company leases office facilities under an operating lease agreement that expires on September 30, 2012. Rent expense was $60,779 and $78,737 for the three month periods ended
March 31, 2009 and 2008, respectively.

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

Years ending in December 31,2009


202,3022010


279,3072011


292,2172012


147,641Total

$
921,467


During
the second quarter of 2008, the Company entered into two-year 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. The terms of that agreement require utilization of the rig and payment of
day rates or the payment of standby rates if the rig is not utilized. The estimated termination fee for the first rig is approximately $4.9 million as of

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5Commitments and Contingencies (Continued)

March 31,
2009. The termination fee on the first rig will continue to decrease as long as the Company keeps the rig active. The second rig has been placed on hold with the drilling contractor.
The Company is negotiating with the drilling contractor to either cancel or delay its obligation with respect to the second rig in an effort to avoid all or a part of the contractual
$5.6 million cancellation penalty.

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

Note 6Credit Facility

On September 11, 2008, our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. ("Kodiak USA"), entered into a $20 million, two-year, revolving,
senior secured credit facility (the "Credit Facility") with Bank of the West, NA ("Bank of the West"). Borrowings made under the Credit Facility are guaranteed by the Company and collateralized by
mortgages on substantially all of our producing oil and gas properties. As of the end of the of the fiscal quarter ending on March 31, 2009, we have a negative trailing 12-month
adjusted EBITDA. As a result, we do not currently satisfy the applicable financial covenant requiring an interest coverage ratio of trailing 12-month adjusted EBITDA to interest of not
less than 3:1. The Company's failure to satisfy this covenant has the effect of immediately suspending Bank of the West's obligation to make advances or issue letters of credit under the Credit
Facility. The Credit Facility also provides for letters of credit that may be used for general corporate purposes. Our aggregate borrowings and outstanding letters of credit under the
Credit Facility may not, at any time, exceed the borrowing base. Interest on borrowings under the Credit Facility accrues at variable interest rates, at our election, at
either:



In
addition, an unused line fee of 0.5%, based on the percentage of borrowing base utilized, will accrue on the unused portion of the commitments under the Credit Facility. The Credit
Facility requires us to comply with financial covenants that require us to maintain (1) a current ratio (defined as current assets plus unused availability under the Credit Facility divided by
current liabilities excluding any mark-to-market assets or liabilities that may occur due to Kodiak's hedging activities), at any time of not less than 1:1; and (2) an
interest coverage ratio of trailing twelve month adjusted EBITDA to interest at any time of not less than 3:1; and (3) a total funded debt to tangible net worth ratio on not more than 2:1 as of
the end of any fiscal quarter. The Credit Facility contains additional representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not
limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on investments covenants and (iii) limitations on reorganizations, recapitalizations,
liquidations, dissolutions, mergers and other combination covenants. Any outstanding principal balance of the revolving loan, together with any unpaid fees and expenses relating thereto, will be due
and payable no later than September 11, 2010.

As
of March 31, 2009, we had no outstanding borrowings under the Credit Facility and we had $227,348 in commercial letters of credit outstanding, which is considered usage (not
borrowings) for purposes of calculating availability and commitment fees. We capitalized deferred financing costs related to the institution of the Credit Facility, which is amortized on a straight
line basis over the term

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6Credit Facility (Continued)

of
the Credit Facility. The borrowing base is re-determined semi-annually, with the May 2009 review currently in process and expected to result in a borrowing base in the
$1.9 million range. To date, we have never borrowed against our Credit Facility, and since March 31, 2009, we have not had any new letters of credit issued.

Kodiak
USA entered into an ISDA Master Agreement (the "Agreement"), dated September 30, 2008, with Bank of the West, under which the Company may 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. Kodiak USA's obligations under the Agreement are collateralized by a Mortgage, Security Agreement, Assignment, Financing Statement and Fixture Filing dated as
of September 11, 2008. The Company is a guarantor of Kodiak USA's obligations under the Agreement and the Agreement is cross-defaulted with Kodiak USA's revolving credit facility with Bank of
the West.

Note 7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 8Subsequent Event

In connection with the Proposed Financing (defined in Note 2) on May 6, 2009, the Company entered into agreements to issue 10.0 million shares of our common stock to
certain institutional investors and insiders, including management, in a non-brokered registered direct offering. The closing of the Proposed Financing, which is expected to take place on
or about May 11, 2009, is subject to the Company obtaining NYSE Amex approval for the listing of the common shares issuable pursuant to the Proposed Financing. The aggregate gross proceeds from
the offering are expected to be approximately $7.5 million, and the aggregate net proceeds, after deducting offering expenses, are expected to be approximately $7.45 million The net
proceeds will be used primarily for drilling and completion activities on the Company's leases in the Bakken oil play located on the Fort Berthold Indian Reservation in North Dakota, and for other
general corporate activities. The common stock being offered in the Proposed Financing has been registered on a universal shelf registration statement on Form S-3
(No. 333-152311) that was filed with the SEC on July 14, 2008 and declared effective by the SEC on July 24, 2008.

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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, 2008 and the
following:



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

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

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

Overview

Kodiak Oil & Gas Corp. ("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:



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

Our
working capital of approximately $10.9 million as of March 31, 2009 is not expected to be sufficient to support all of our currently planned exploration activities in
2009. Working capital includes approximately $8.3 million of tubular goods included within prepaid expense and other, which are more fully discussed herein. To address our current working
capital requirements, on May 6, 2009, we entered into agreements to sell 10.0 million shares of our common stock to certain institutional investors and insiders, including management, in
a non-brokered registered direct offering ("Proposed Financing"). The closing of the Proposed Financing, which is expected to take place on or about May 11, 2009, is subject to the
Company obtaining NYSE Amex approval for the listing of the common shares issuable pursuant to the Proposed Financing. The common stock being offered has been

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registered
on a universal shelf registration statement on Form S-3 (No. 333-152311) that was filed with the SEC on July 14, 2008 and declared effective by
the SEC on July 24, 2008. The aggregate gross proceeds from the Proposed Financing are expected to be approximately $7.5 million, and the aggregate net proceeds, after deducting offering
expenses, are expected to be approximately $7.45 million. The net proceeds will be used primarily for drilling and completion activities on the Company's leases in the Bakken oil play located
on the Fort Berthold Indian Reservation in North Dakota and for other general corporate activities. If we are unable to close the Proposed Financing, we will need to pursue alternative sources of
financing. For more information on our current need for capital and the Proposed Financing, see the section below entitled "Liquidity and Capital Resources."

During
the second quarter of 2008, the Company entered into two-year contracts for the use of two new-build drilling rigs. The first rig was placed into operation
in November 2008 under an agreement that provides for a two year drilling commitment or specific termination fees if drilling activity is cancelled. The terms of that agreement require utilization of
the rig and payment of day rates or the payment of standby rates if the rig is not utilized. The estimated termination fee for the first rig is approximately $4.9 million as of March 31,
2009, which reflects a $0.4 million decrease from the estimated termination fee at December 31, 2008 of $5.3 million. The decrease in the
termination fee is due to continued use of the rig, and the termination fee will continue to decrease so long as we keep the rig active. The second rig has not yet been delivered, and we are
negotiating with the rig contractor to either cancel or delay our obligation with respect thereto to avoid all or a part of the potential contractual $5.6 million cancellation penalty. We
cannot offer any assurance that we will be able to negotiate a satisfactory resolution to this issue. Both we and the rig owner are attempting to locate another entity that will agree to assume our
obligations under the contract, although there can be no assurance that we will be able to do so. The penalties associated with the termination of one or both of the Company's drilling rig contracts
exceeds the Company's current cash and cash equivalents at March 31, 2009.

Recent Developments

Williston Basin OperationsDunn County, North Dakota

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

Drilling Activity

The Moccasin Creek #16-34-2H well (Kodiak operates with 60% working interest ("WI") and 49% net revenue
interest ("NRI")) reached total depth in January 2009. Located in the southwestern portion of Kodiak's leasehold, the well was drilled on 320-acre spacing to an approximate total vertical
depth ("TVD") of 10,350 feet and a total measured depth ("TMD") of 15,525 feet with 4,169 feet of lateral in the middle Bakken. The well successfully reached TMD and had the liner in the hole in
41 days. Completion operations are discussed below.

The
Moccasin Creek #16-34H well (Kodiak operates with 60%WI and 49% NRI) reached total depth in February 2009. The well was drilled on 320-acre spacing to an
approximate TVD of 10,350 feet and a TMD of 14,810 feet with 4,159 feet of lateral in the middle Bakken. The well successfully reached TMD and had the liner in the hole in 36 days. Completion
operations are discussed below.

The
Two Shields Butte #16-8-16H well (Kodiak operates with 50% WI and 41% NRI) reached total depth in March 2009. The well, located in the northwestern portion of
Kodiak's leasehold, was drilled on 320-acre spacing to an approximate TVD of 10,350 feet and a TMD of 15,760 feet with 4,465

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feet
of lateral in the middle Bakken. The well successfully reached TMD and had the liner in the hole in 31 days. Completion operations are anticipated to commence in late May 2009.

The
Two Shields Butte #16-8-7H well (Kodiak operates with 37.5% WI before payout and 30% NRI before payout) reached total depth in April 2009. The well, located
in the northwestern portion of Kodiak's leasehold, was drilled to an approximate TVD of 10,350 feet and a TMD of 19,743 feet with 8,995 feet of lateral in the middle Bakken. The well, drilled on a
640-acre drill site comprised of two lay down 320-acre tracts, successfully reached TMD and had the liner in the hole in 28 days. Completion operations are anticipated
to commence in June 2009.

We
are in the process of moving our drill rig to the Two Shields Butte #14-33-6H well drilling pad (Kodiak operates with 50% WI and 41% NRI).

Completion Activity

Fracture stimulation procedures were completed on the Moccasin Creek #16-34-2H well on April 23, 2009.
During drilling operations, a liner was run into the 4,169 foot horizontal lateral section of the well bore utilizing sliding sleeves with the expectation of an eight-stage fracture stimulation
design. During completion operations, the well encountered mechanical issues when one of the sleeves inadvertently opened, preventing stimulation procedures to be completed on four of the eight
stages. As a result, only four fracturing stages were successfully put away in the intended zones. At this time, the well will be produced and the production rates will be monitored. No further
near-term work is anticipated, although additional stimulation work may be completed at a later date. The well is currently flowing back and oil and fracturing fluid up
41/2" frac string to the tank batteries. Initial 24-hour production rates were 604 barrels of oil and approximately 643 thousand cubic feet per day (Mcf/d) of natural
gas, or 711
BOE. The well is only being produced during non-working hours as completion work on the Moccasin Creek #16-34H continues from the same drilling pad

Fracture
stimulation procedures were completed on the Moccasin Creek #16-34H well on May 4, 2009. The well was completed utilizing sliding sleeves with a
five-stage fracture stimulation design in the 4,159 foot horizontal lateral section of the well bore. The well is currently flowing back fracturing fluids and oil up 41/2"
frac string to the tank batteries. Initial 24-hour production rates were 1,274 barrels of oil and 717 Mcf/d of natural gas, or 1,394 BOE.

As
of March 31, 2009, Kodiak had approximately 54,000 gross and 37,000 net acres under lease on the Fort Berthold Indian Reservation ("FBIR"). Kodiak operates all of its leasehold
on the FBIR, with the exception of approximately 18,000 gross and 9,000 net acres that are in a participating area previously established with another operator. As we move through 2009, our capital
will be committed to the drilling of wells on the FBIR in North Dakota. As part of this strategy, we have deferred our plans for drilling on other acreage in North Dakota and Montana that are outside
the Bakken oil play and on prospect acreage that we have acquired in Wyoming.

Production, Average Sales Prices, and Production Costs

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

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The
Company's oil and gas sales volumes are directly related to the results of its exploratory and acquisition activities. Production volumes may vary monthly as various wells are
completed or maintained in an effort to provide optimal production. Sales volumes, prices received and production costs are summarized in the following table for the three month periods ended
March 31, 2009 and March 31, 2008.

For the three months endedMarch 31, 2009

March 31, 2008Sales Volume:Gas (Mcf)


99,694


66,600Oil (Bbls)


16,486


15,848Production volumes (BOE)


33,101


26,948Price:Gas ($/Mcf)

$
2.83

$
6.99Oil ($/Bbls)

$
30.04

$
89.12Production costs ($/BOE):Lease operating expenses

$
4.15

$
29.48Production and property taxes

$
(0.80
)
$
5.87Gathering, Transportation & Marketing

$
1.14

$
1.13


Credit Facility

We currently do not satisfy one of the financial covenants under our Credit Facility requiring us to maintain an interest coverage
ratio of trailing 12-month adjusted EBITDA to interest at any time of not less than 3:1 ("Interest Coverage Covenant"). The Company's failure to satisfy the Interest Coverage Covenant has
the effect of immediately suspending Bank of the West's obligation to make advances or issue letters of credit to us under the Credit Facility. For more information concerning the Credit Facility, see
Note 5 to the financial statements included above, which is incorporated by reference herein.

Results of Operations

For the Three Months Ended March 31, 2009 compared to the Three Months Ended March 31, 2008

The Company reported a net loss for the three months ended March 31, 2009 of $1.6 million, compared to a net loss of
$2.6 million for the same period in 2008. The Company's net loss for the

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three
months ended March 31, 2009 was primarily due to lower oil and natural gas prices realized in the first three months of 2009 compared to the first three months of 2008.

For the three months endedMarch 31, 2009

March 31, 2008Financial ResultsTotal revenue

$
791,360

$
1,961,537Total costs and expenses


2,418,967


4,593,573Net loss

$
(1,627,607
)
$
(2,632,036
)Diluted net loss per common share

$
(0.02
)
$
(0.03
)Capital Resources and LiquidityCash and cash equivalents at end of the period

$
2,007,423

$
9,904,019Net cash provided by (used in) operating activities

$
(2,473,391
)
$
(2,428,942
)Capital expendituresoil and gas properties excluding accruals and proceeds from divestitures

$
3,817,427

$
690,569Adjusted EBITDA (see below discussion)

$
(491,731
)
$
2,354


Oil and Gas Revenue and Production

During the three-month period ended March 31, 2009, as compared to the same period in 2008, natural gas production volumes
increased 50% due to new production coming on-line in late 2008, while crude oil production volumes increased 4%. Total gas price realizations decreased 60% to $2.83 per Mcf for the three
month period ended March 31, 2009, compared to $6.99 per Mcf for the same period in 2008. Oil price realizations declined by 66% to $30.04 per barrel for the three month period ended
March 31, 2009, compared to $89.12 for the same period in 2008. Primarily due to the decline in both oil and natural gas pricing, oil and gas revenues declined by $1.1 million to
$0.8 million for the three month period ended March 31, 2009, compared to the same period in 2008.

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of $148,529 during the three month period ended
March 31, 2009, as compared to $982,951 during the same period in 2008. In the first quarter of 2008, we performed workover operations on our producing Bakken oil wells in McKenzie County, ND.
The net cost of approximately $467,000 related to the repair work was charged to oil and gas production costs and expenses in the first quarter of 2008. In addition, during the first three months of
2009, the Company reconciled and recorded outstanding ad valorem tax accruals resulting in a credit of approximately $93,000. Furthermore, we have shut in certain oil and gas wells due to low
commodity prices which rendered the wells non-commercial, further reducing our lease operating expense.

Depletion, Depreciation and Amortization

Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was $0.4 million for the three month period
ended March 31, 2009, compared to $1.1 million for the same period in 2008. DD&A expense decreased during the quarter due to the impairment charges taken in 2008 which reduced the full
cost pool by $47.5 million year over year thereby decreasing the DD&A expense recorded.

Ceiling Test Impairment

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income
taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of

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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, 2009 and 2008, no impairment charges were recorded.

General and Administrative Expense

The Company's general and administrative costs of $1.9 million for the three months ended March 31, 2009 compared to
$2.5 million for the same period in 2008. This 24% reduction for the period is primarily due to lower stock-based compensation expense of $0.8 million recorded for the three months ended
March 31, 2009 compared to $1.5 million recorded for the same period in 2008, related to options and restricted stock issued to officers, directors and employees. This reduction in the
stock-based compensation expense is primarily due to no issuance of stock options in the first quarter of 2009, as well as a larger number of stock option forfeitures in the first quarter of 2009 as
compared to the same period in 2008. Excluding the non-cash stock-based compensation expense in each period, our general and administrative costs were comparable. While we have reduced
certain components of our overhead in 2009, the decrease was offset by a $160,000 accrual adjustment recorded in the first quarter of 2008.

EBITDA

In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gain on foreign
currency, stock-based compensation expense and accretion of abandonment liability ("Adjusted EBITDA") as a key indicator of financial operating performance and as a measure of the ability to generate
cash for operational activities, future capital expenditures and servicing of borrowings under the Company's Credit Facility. The Company's Adjusted EBITDA decreased by $0.5 million to a
negative amount of $0.5 million for the three months ended March 31, 2009 from the same period in 2008. The decrease in Adjusted EBITDA was primarily the result of the significant
decrease in oil and natural gas pricing during the period as compared to the same period in 2008. Adjusted EBITDA is not a Generally Accepted Accounting Principle ("GAAP") measure of performance. The
Company uses this non-GAAP measure primarily to compare its performance with other companies in the industry that make a similar disclosure and as a measure of its current liquidity. The
Company believes that this measure may also be useful to investors for the same purpose and for an indication of the Company's ability to generate cash flow at a level that can sustain or support our
operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for operating income or loss, cash flow from operations determined under GAAP or
any other measure for determining the Company's operating performance that is calculated in accordance with GAAP. In addition, because Adjusted EBITDA is not a GAAP measure, it may not necessarily be
comparable to similarly titled measures employed by other companies. A reconciliation of Adjusted EBITDA and net income for the three months ended March 31, 2009 and 2008 is provided in the
table below:

Three months ended
March 31,
2009

Three months ended
March 31,
2008Reconciliation of Adjusted EBITDA:Net Loss

$
(1,627,607
)
$
(2,632,036
)Add back:Depreciation, depletion, amortization and accretion


355,340


1,097,299(Gain) / loss on foreign currency exchange


(853
)

18,281Stock based compensation expense


781,389


1,518,810Adjusted EBITDA

$
(491,731
)
$
2,354


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Table of Contents

Liquidity and Capital Resources

The following table sets forth our liquidity and capital resources as of three months ended March 31, 2009 and 2008:

For the three months ended
March 31,2009

2008Capital Resources and LiquidityCash and cash equivalents at end of the period

$
2,007,423

$
9,904,019Net cash provided by (used in) operating activities


(2,473,391
)

(2,428,942
)Net cash used in investing activities


(3,100,451
)

(682,357
)Net cash flow


(5,573,842
)

(3,111,299
)


Kodiak
ended the first quarter of 2009 with cash and cash equivalents of $2.0 million as compared to $7.6 million at year-end 2008. Total working capital was
$10.9 million at March 31 2009, as compared to $15.4 million at December 31, 2008. As of March 31, 2009, we had prepaid $8.3 million towards the cost of
tubular goods ($5.8 million of tubular goods and surface equipment that are inventoried in third party yards and $2.5 million of deposits for tubular goods that will be delivered later
this year), compared to $9.7 million at December 31, 2008. With respect to the decrease in prepaid tubular goods and surface equipment of $1.4 million from December 31,
2008 to March 31, 2009, approximately $0.9 was charged to our properties, $0.7 was billed out to third parties and an additional $0.2 was prepaid for tubular goods during 2009. The
$5.8 million of inventoried tubular goods as of March 31, 2009 has been reduced to approximately $5.1 million as of May 1, 2009, and the majority of this balance will be
charged in the next three wells that are scheduled to be drilled consecutively. Net cash flow used in operating activities for the first three months of 2009 was $2.5 million. Net cash usage
was the result of the costs of our operations exceeding our revenues due to reduced oil and natural gas prices realized during the period. Net cash used as investing activities (which includes
recoupments from partners and restricted cash changes) totaled $3.1 million for the first three months of 2009. These investing items were comprised of $4.4 million for oil and gas
capital investments on an accrued accounting basis and then adjusted for prepaid tubular goods, expense accruals, and asset retirement obligations, resulting in a cash basis oil and gas capital
investment of $3.8 million for the first three months of 2009.

Kodiak's
results of operations and financial condition are significantly affected by the success of our exploration and land leasing activity, the resulting production and reserves, oil
and natural gas commodity prices and the costs related to operating our properties. In the first three months of 2009, our oil and natural gas revenue decreased by 59% from $1.9 million as of
March 31, 2008 to $0.8 million as of March 31, 2009. This decrease is largely the result of the decrease in crude oil and natural gas pricing realized during the first three
months of 2009 as compared to the first three months of 2008. Total lease operating costs and expenses decreased to $2.0 million for the first three months of 2009 from $4.6 million for
the first three months of 2008, largely due to workover expenses incurred in 2008. The decrease in general and administrative expenses included a decrease in the non-cash charge for stock
based compensation from $1.5 million during the first three months of 2008 to $0.8 million during first three months of 2009. This reduction in general and administrative expenses was
primarily due to a lower stock-based compensation expense caused by no issuance of stock options in the first quarter of 2009, as well as a larger number of option forfeitures in the first quarter in
2009 as compared to the same period in 2008.

During
the first three months of 2009, we incurred capital expenditures of approximately $4.4 million. We anticipate total net capital expenditures of up to $15.3 million
in 2009, compared to approximately $11.0 million incurred in 2008, although such estimate does not include any potential costs or fees associated with the second drill rig that we have
contracted and are now attempting to

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terminate
or defer our obligation to a later date. We continue to evaluate and monitor our capital expenditures in relation to commodity prices. Our expenditures could be less than
$15.3 million in 2009 if our costs associated with drilling continue to decline, our activities are constrained by a lack of sufficient capital or commodity prices cause us to choose not to
invest in certain exploration activities currently planned. We originally estimated that, of the $15.3 million total projected expenditures, $4.0 million would be allocated to the
Vermillion Basin of Wyoming and Colorado and the remaining $11.3 million would be allocated to the Williston Basin of North Dakota. However, our projections have since changed, and we now
anticipate that actual expenditures during 2009 in the Vermillion Basin will be less than $4.0 million, in which case we anticipate that the difference in the budgeted amount for the Vermillion
Basin and actual expensitures will be re-allocated to the Williston Basin. The actual allocation of our expenditures between the Williston Basin and Vermillion Basin will be dependent on
future events, including the exploration decisions made by our partners in these areas.

As
noted above, we do not currently have sufficient working capital to support our projected 2009 capital expenditure program. To address our current working capital requirements, we
expect to raise approximately $7.45 million in capital (net of offering expenses) in May 2009 pursuant to the Proposed Financing. If the Proposed Financing closes as expected, we anticipate
that the resulting net proceeds of $7.45 million, together with our projected 2009 cash flows from operations and our prepaid tubular goods and surface equipment, would be sufficient to support
our planned capital expenditure program through December 2009. If we are unable to close the Proposed Financing, or if we realize lower than expected cash flows from operations, either due to lower
than anticipated production or commodity prices, we would need to pursue alternative sources of financing that may include entering into additional joint venture agreements, selling off interests (and
perhaps substantial interests) in our oil and gas properties or issuing debt or equity securities outside of the Proposed Financing. We cannot be certain that additional funding will be available on
acceptable terms, or at all. Furthermore, as previously discussed, we are not currently eligible to access our Credit Facility to borrow funds due to our failure to satisfy the Interest Coverage
Covenant. If we are unable to secure additional capital when required or on acceptable terms, we may have to significantly delay, scale back or discontinue our drilling or exploration program, seek to
enter into additional joint venture arrangements with third parties, or seek to sell one or more of our properties. A significant delay in obtaining additional financing would have a material adverse
effect on our business.

During
the second quarter of 2008, the Company entered into two-year contracts for the use of two new-build drilling rigs. The first rig was placed into operation
in November 2008 under an agreement that provides for a two year drilling commitment or specific termination fees if drilling activity is cancelled. The terms of that agreement require utilization of
the rig and payment of day rates or the payment of standby rates if the rig is not utilized. The estimated termination fee for the first rig is approximately $4.9 million as of March 31,
2009, which reflects a $0.4 million decrease from the estimated termination fee at December 31, 2008 of $5.3 million. The decrease in the termination fee is due to continued use
of the rig, and the termination fee will continue to decrease so long as we keep the rig active. The second rig has not yet been delivered, and we are negotiating with
the rig contractor to either cancel or delay our obligation with respect thereto to avoid all or a part of the potential contractual $5.6 million cancellation penalty. We cannot offer any
assurance that we will be able to negotiate a satisfactory resolution to this issue. Both we and the rig owner are attempting to locate another entity that will agree to assume our obligations under
the contract, although there can be no assurance that we will be able to do so. The penalties associated with the termination of one or both of the Company's drilling rig contracts exceeds the
Company's current cash and cash equivalents at March 31, 2009.

The
following tables set forth our capital expenditures for the three months ended March 31, 2009 and our maximum planned capital expenditures for our principal properties in
2009. Net capital

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expenditures
include both cash expenditures and accrued expenditures and are net of proceeds from divestitures.

Net Capital
Expenditures
For the Three
Month Ended
March 31, 2009
($000)

Total 2009
Budgeted Net
Capital
Expenditures
($000)Project LocationWyomingVermillion Basin wells and related infrastructure

$
50

$
4,000Other Wyoming wells and related infrastructure


1


Acreage/Seismic


(15
)

Total Wyoming

$
36

$
4,000Williston BasinMission Canyon/Red River wells and related


(21
)

700Bakken wells and related infrastructure


3,838


10,055Acreage/Seismic


547


500Total Williston Basin

$
4,364

$
11,255Total All Areas

$
4,400

$
15,255






Oil and Gas Properties

As of March 31, 2009, we had several hundred lease agreements representing approximately 167,200 gross and 99,500 net acres,
primarily in the Green River and Williston Basins.

As
of March 31, 2009, we had an interest in approximately 54,000 gross acres and 37,000 net acres in the Bakken oil play in Dunn County, North Dakota. The majority of our lands in
this area are administered by the Bureau of Indian Affairs on behalf of the individual members of the Three Affiliated Tribes 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.

Our
leasehold interests in the Vermillion Basin total approximately 44,000 gross and 17,000 net acres as of March 31, 2009. Our area of mutual interest with Devon will expire on
January 1, 2013, unless extended by mutual agreement of the parties. Each party has agreed to an equal share of any

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Table of Contents

interest
or lease acquired within the participating area. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of March 31, 2009.

Undeveloped Acreage(1)

Developed Acreage(2)

Total AcreageGross

Net

Gross

Net

Gross

NetGreen River BasinWyoming(3)


42,422


17,349


1,520


908


43,942


18,257Colorado


7,419


4,986


0


0


7,419


4,986Williston BasinMontana


33,621


20,022


800


400


34,421


20,422North Dakota


65,468


42,924


3,360


1,992


68,828


44,916Other BasinsWyoming


12,562


10,875


0


0


12,562


10,875Acreage Totals


161,492


96,156


5,680


3,300


167,172


99,456


---

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 2009 or the following three years and have no options for renewal
or are not included in federal units:

Expiring AcreageYear Ending

Gross

NetDecember 31, 2009


11,714


5,755December 31, 2010


31,101


16,607December 31, 2011


7,791


3,773December 31, 2012


32,403


19,342Total


83,009


45,477


Off-Balance Sheet Arrangements

Other than standard operating leases and our drilling rig commitments, we do not have any off-balance sheet financing
arrangements at March 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,
2008, which is incorporated herein by reference.

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Recently Issued Accounting Pronouncements

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162,The Hierarchy of
Generally Accepted Accounting Principles("SFAS 162"). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to
be used in the preparation of financial statements that are presented in conformity with U.S. generally accepted accounting principles. The Statement becomes effective 60 days following the
SEC's approval of the Public Company Accounting Oversight Board amendments to the auditing literature. The adoption of SFAS 162 will not have an impact on the Company's financial position,
results of operations or cash flows.

On
December 12, 2007, the SEC published a Concept Release on possible revisions to the disclosure requirements relating to oil and gas reserves as specified in
Rule 4-10 of Regulation S-X and Item 102 of regulation S-K. On December 31, 2008, the SEC adopted a final rule that amends its
oil and gas reporting requirements. The revised rules change the way oil and gas companies report their reserves in the financial statements. Definitions were updated to be consistent with Petroleum
Resource Management System (PRMS). Other key revisions include a change in pricing used to prepare reserve estimates, the inclusion of non-traditional resources in reserves, the allowance
for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and other new disclosures.
The revised rules are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years
ending December 31, 2009, and after. The SEC is precluding application of the new rules in quarterly reports prior to the first annual report in which the revised disclosures are required.
Early adoption is not permitted. The changes are considered a change in accounting principle that is inseparable from a change in accounting estimate pursuant toFASB Statement
No. 154, Accounting Changes and Error Corrections, and should be accounted for prospectively. Management is evaluating the impact of the adoption of this final SEC
ruling on disclosure requirements relating to our oil and gas reserves and does not anticipate that the implementation of the new reporting requirements will have a material impact on the consolidated
results of operations, financial position or liquidity.

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Table of Contents

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 $99,694 change in our gross gas production revenue. A $1.00 per
barrel change in the market price of oil will result in an approximate $16,486 change in our gross oil production revenue. The impact on any potential sale of property cannot be readily determined.

Interest Rate Fluctuations

We currently maintain 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
$37,531 annual impact if all of our cash, as of March 31, 2009, 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, 2009. 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.

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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Table of Contents

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, 2008, 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, 2008, 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

Our current working capital will not be sufficient to support all our planned exploration opportunities in 2009.

Our working capital of $10.9 million as of March 31, 2009 will not be sufficient to support all of our planned
exploration opportunities in 2009. Our plan of operations for 2009 contemplates capital expenditures of $15.3 million for the development of existing properties and anticipated property
acquisitions. Pursuant to the Proposed Financing, we expect to raise net proceeds of $7.45 million during May 2009. If the Proposed Financing closes as expected, we anticipate that the
resulting net proceeds of $7.45 million, together with our projected 2009 cash flows from operations and our prepaid tubular goods and surface equipment, would be sufficient to support our
planned oil and natural gas exploration program through December 2009. If the Proposed Financing does not close, or if we realize lower than expected cash flows from operations, either due to lower
than anticipated production or commodity prices, we will need to seek alternative sources of capital, including by means of entering into joint ventures with other exploration and production
companies, sales of interests in certain of our properties or by undertaking additional financing activities. However, future financing may not be available in amounts or on terms acceptable to us, if
at all. Any future issuances of equity may be at prices below the market price of our stock, and our shareholders may suffer significant dilution. 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. If we were to borrow funds, we will be obligated to make periodic interest or
other debt service payments and may
be subject to additional restrictive covenants. Our Credit Facility is not currently available to us due to our failure to satisfy the Interest Coverage Covenant. Our failure to obtain financing in a
timely basis or on favorable terms could result in the loss or substantial dilution of our interests in our properties as disclosed in this Form 10-Q.

In
addition, the failure of any of us or our joint venture partners to obtain any required financing could adversely affect our ability to complete the exploration or development of any
of our joint venture projects on a timely basis. This could result in the curtailment of operations relating to exploration and development of our prospects, which in turn could lead to a possible
loss of properties and a decline in our natural gas and oil reserves.

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Table of Contents

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, the Company entered into two-year 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. The estimated
termination fee for the first rig is approximately $4.9 million as of March 31, 2009. The termination fee on the first rig will continue to decrease so long as we keep the rig active.
Our second rig has been placed on hold with the drilling contractor. We are negotiating with the drilling contractor to either cancel or delay our obligation with respect to the second rig and avoid
all or a part of the contractual $5.6 million cancellation penalty. We cannot offer any assurance that we will be able to negotiate a satisfactory resolution to this issue. Both we and the rig
owner are attempting to find another company that will take over our obligations, although there can be no assurance that we will be able to do so. If we 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. The contractual penalties associated with the termination of one or both of the
Company's drilling rig contracts exceeds the Company's current cash and cash equivalents at March 31, 2009.

The proposed United States federal budget for fiscal year 2010 includes certain provisions that, if passed as originally submitted, could have an adverse effect on our
financial position, results of operations and cash flows.

On February 26, 2009, the federal Office of Management and Budget released a summary of the President's proposed federal budget
for fiscal year 2010. The proposed budget repeals many tax incentives and deductions that are currently used by US oil and gas companies
and imposes new taxes. The provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; increases in the taxation of foreign source income; repeal of
the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on
non-producing leases located on federal lands.

Should
some or all of these provisions become law, there could be a negative impact on our net income and cash flows. This could also reduce our drilling activities. Since none of these
proposals have yet to be voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.

Risks Related to our Common Stock

The closing of the Proposed Financing and any other future sales or issuances of our common stock could depress the market for our common stock and will cause shareholder
dilution.

On July 14, 2008, we filed a shelf registration statement on Form S-3 (SEC file
No. 333-152311), which was declared effective by the SEC on July 24, 2008. In connection with the Proposed Financing, we intend to issue 10.0 million shares of our
common stock pursuant to our effective shelf registration statement. The anticipated closing of the Proposed Financing and any other sales of large quantities of our common stock could reduce the
price of our common stock and operate to dilute our existing stockholders' ownership.

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

None.

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5.    OTHER INFORMATION

None.

ITEM 6.    EXHIBITS

Exhibit Number

Description31.1

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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Table of Contents

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 7, 2009

/s/ LYNN A. PETERSON Lynn A. Peterson President and Chief Executive OfficerMay 7, 2009

/s/ JAMES KEITH DOSS James Keith Doss Chief Financial Officer(principal financial officer)


34

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