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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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 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

104,729,431 shares, no par value, of the Registrant's Common Stock were issued and outstanding as of July 31, 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

19ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

33ITEM 4.

CONTROLS AND PROCEDURES

33PART IIOTHER INFORMATION

34ITEM 1.

LEGAL PROCEEDINGS

34ITEM 1A.

RISK FACTORS

34ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

34ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

34ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

34ITEM 5.

OTHER INFORMATION

35ITEM 6.

EXHIBITS

35SIGNATURES

36


1

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PART 1FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)
June 30,
2009

December 31,
2008ASSETSCurrent Assets:Cash and cash equivalents

$
3,821,907

$
7,581,265Accounts receivableTrade


2,733,630


1,934,818Accrued sales revenues


1,637,322


516,870Prepaid expenses and other


7,722,543


10,621,980Total Current Assets


15,915,402


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


106,438,597


97,934,058Unproved oil and gas properties


12,530,735


11,985,533Wells in progress


4,369,900


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


(93,592,216
)

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


29,747,016


17,842,773Other property and equipment, net of accumulated depreciation of $249,998 in 2009 and $270,620 in 2008


220,371


272,705Restricted investments





246,068Total Assets

$
45,882,789

$
39,016,479LIABILITIES AND STOCKHOLDERS' EQUITYCurrent Liabilities:Accounts payable and accrued liabilitiesNote 9

$
5,114,238

$
4,125,335Advances from joint interest owners


492,806


1,105,740Total Current Liabilities


5,607,044


5,231,075Noncurrent Liabilities:Asset retirement obligation


976,026


787,180Total Liabilities


6,583,070


6,018,255Commitments and ContingenciesNote 6Stockholders' Equity:Common stockno par value; unlimited authorizedIssued and outstanding: 104,729,431 shares in 2009 and 95,129,431 shares in 2008Contributed surplus


144,765,100


136,297,845Accumulated deficit


(105,465,381
)

(103,299,621
)Total Stockholders' Equity


39,299,719


32,998,224Total Liabilities and Stockholders' Equity

$
45,882,789

$
39,016,479


SEE
ACCOMPANYING NOTES

2

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

Three months ended June 30,

For the Six Months Ended
June 30,2009

2008

2009

2008Revenues:Gas production

$
129,329

$
462,218

$
411,803

$
928,083Oil production


1,860,808


1,501,588


2,356,066


2,913,894Interest & other


22,893


36,884


36,520


120,250Total revenue


2,013,030


2,000,690


2,804,389


3,962,227Cost and expenses:Oil and gas production


343,674


1,282,618


492,203


2,265,569Depletion, depreciation, amortization and accretion


532,454


786,777


887,794


1,884,076General and administrative


1,680,344


1,831,508


3,596,295


4,326,551(Gain)/loss on currency exchange


(5,288
)

(1,772
)

(6,142
)

16,508Total costs and expenses


2,551,184


3,899,131


4,970,150


8,492,704Net loss

$
(538,154
)
$
(1,898,441
)
$
(2,165,761
)
$
(4,530,477
)Basic & diluted weighted-average common shares outstanding


100,235,806


88,033,107


97,696,724


88,013,019Basic & diluted net loss per common share

$
(0.01
)
$
(0.02
)
$
(0.02
)
$
(0.05
)


SEE
ACCOMPANYING NOTES

3

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Table of Contents

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

Six Months Ended June 30,2009

2008Cash flows from operating activities:Net loss

$
(2,165,761
)
$
(4,530,477
)Reconciliation of net loss to net cash (used in) provided by operating activities:Depletion, depreciation, amortization and accretion


887,794


1,884,076Stock based compensation


1,375,080


1,967,511Changes in current assets and liabilities:Accounts receivable-trade


(798,812
)

(776,323
)Accounts receivable-accrued sales revenue


(1,120,452
)

(53,118
)Prepaid expenses and other


1,750,921


(1,941,424
)Accounts payable and accrued liabilities


(622,402
)

(1,720,237
)Net cash (used in) operating activities


(693,632
)

(5,169,992
)Cash flows from investing activities:Oil and gas properties


(9,407,721
)

(9,171,252
)Sale of oil and gas properties





2,437,892Equipment


8,000


(2,124
)Prepaid tubular goods


(993,413
)

Restricted investment: undesignated as restricted


235,233


10,835Net cash (used in) investing activities


(10,157,901
)

(6,724,649
)Cash flows from financing activity:Proceeds from the issuance of shares


7,200,000


78,750Issuance costs


(107,825
)

Net cash provided by financing activities


7,092,175


78,750Net change in cash and cash equivalents


(3,759,358
)

(11,815,891
)Cash and cash equivalents at beginning of the period


7,581,265


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

$
3,821,907

$
1,199,427Supplemental cash flow informationOil & gas property accrual included in Accounts payable and accrued liabilities

$
2,455,560

$
1,338,899Asset retirement obligation

$
139,290

$
(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

In May 2009, the Company entered into agreements to issue 9,600,000 shares of our common stock to certain institutional investors in a
non-brokered registered direct offering (the "Financing"). The Financing closed on May 14, 2009, resulting in net proceeds of $7,092,175. We anticipate that these proceeds, together
with our projected 2009 cash flows from operations and our prepaid tubular goods and surface equipment, will be sufficient to support our planned capital expenditure program through December 2009. If
we have lower than expected cash flows from operations, either due to lower than anticipated production or lower commodity prices, or if the Company increases its planned 2009 capital expenditure
program, 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 these capital-raising activities will be affected by prevailing economic conditions in its
industry and

5

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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 June 30, 2009, the Company had approximately $2.8 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 June 30, 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 June 30, 2009 we had approximately $7.5 million (consisting of $6.0 million of tubular goods and surface equipment that are inventoried in third-party
yards and $1.5 million of deposits for tubular goods that will be delivered later this year at such time that the tubular goods are required) and $9.7 million as of December 31,
2008 comprised of $7.2 million in tubular goods and surface equipment and $2.5 million of deposits. In respect of the

6

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

$1.5 million
tubular goods deposit, as of June 30, 2009, the Company estimates that an additional $2.2 million will be paid to complete the purchase and if the purchases are not
completed the deposits would be forfeited. The cost basis of the tubular goods is either depreciated as a component of oil and gas properties once the inventory is used in drilling operations or
billed to our partners through joint interest billings. The Company records tubular goods inventory at the lower of cost or market value. As of June 30, 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 and any differences were not deemed material. With the current level of drilling activity and requirements for tubular goods, it is anticipated that the
prepaid amount will remain at a relatively constant level from period to period.

Restricted Investment

The restricted investments are no longer used as security for our outstanding letters of credit and there are no longer any
short-term certificates of deposits as of June 30, 2009. The Company's credit facility (see Note 7) is now used as security for our currently outstanding letters of credit.

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
six months ended June 30, 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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Table of Contents

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 six month periods ended June 30, 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 June 30, 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 six months ended June 30,
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 Agreement,
which are being amortized over the two-year term of the Credit Facility (see Note 7). The Company recorded amortization expense of $12,744 in the six month period ended
June 30, 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 June 30, 2009 and December 31, 2008 were not significant.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation
recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the
long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the condensed
consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligations that have
been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values,
associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are also included in the ceiling test calculation. The asset retirement
liability is allocated to operating expense using a systematic and rational method. As of June 30, 2009, and December 31, 2008, the Company has recorded a net asset of $832,445 and
$501,900 and a related liability of $976,026 and $787,180, respectively. The information below reconciles the value of the asset retirement obligation for the periods presented.

For the Period EndedJune 30, 2009

December 31, 2008Balance beginning of period

$
787,180

$
874,498Liabilities incurred


139,290


Liabilities settled





(147,252
)Accretion expense


49,556


59,934Balance end of period

$
976,026

$
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 June 30, 2009 and December 31, 2008.

Recently Adopted Accounting Pronouncements

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

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

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 was 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
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

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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)

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.

In
May 2009, the FASB issued Statement of Financial Accounting Standards No. 165,Subsequent Events("SFAS 165").
SFAS 165 provides guidance for management's assessment of subsequent events. An additional disclosure required by SFAS 165 is to identify the 'as of' date of the subsequent event.
SFAS 165 is effective for interim and annual reporting periods ending after June 15, 2009. The adoption of SFAS 165 did not have a material impact on the Company's financial
position or results of operations.

Recently Issued Accounting Pronouncements

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.

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 became effective November 15, 2008. In June 2009, the FASB issued
Statement of Financial Accounting Standards No. 168,The FASB Accounting Standards Codification("SFAS 168"). SFAS 168 will become
the source of authoritative U.S. GAAP recognized by the FASB, effectively superseding SFAS 162. SFAS 168 is effective for interim and annual reporting periods ending after
September 15, 2009. The adoption of SFAS 168 will not have a material impact on the Company's financial position or results of operations.

12

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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 six months ended June 30, 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 Six
Months Ended
June 30,
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


9,114,530


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


(5,472,723
)

(414,074
)Ending balance

$
4,369,900

$
728,093


Note 4Common Stock

In May 2009, the Company entered into agreements to sell 9,600,000 shares of our common stock to certain institutional investors, in a non-brokered registered direct
offering. The common stock offered was registered on a universal shelf registration statement on Form S-3 (No. 333-152311) that was filed with the SEC on
July 14, 2008 and declared effective by the SEC on July 24, 2008. The aggregate gross proceeds from the offering were $7,200,000. The Company paid $107,825 in expenses related to the
offering. The net proceeds will be used primarily for drilling and completion activities on our leases in the Bakken oil play located on the Forth Berthold Indian Reservation in North Dakota and for
other general corporate activities.

Note 5Stock-based Compensation Plan

In 2007, the Company adopted the 2007 Stock Incentive Plan (the "2007 Plan"), which replaced the Incentive Share Option Plan (the "Pre-existing Plan"). The 2007 Plan
authorizes the Company to issue stock options, stock appreciation rights (SARs), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based
awards to any employee, consultant, independent contractor, director or officer of the Company. A total of 8,000,000 shares of common stock may be issued under the 2007 Plan, which includes shares
issuable under the Pre-existing Plan pursuant to options outstanding as of the effective date of the 2007 Plan. No more than 8,000,000 shares may be used for stock issued pursuant to
incentive stock options and the number of shares available for granting restricted stock and restricted stock units shall not exceed 1,000,000, subject to adjustment as defined in the 2007 Plan. The
Company granted 1,150,000 stock options at $1.18 per share and 1,481,000 stock options at $2.87 per share during the six month periods ended June 30, 2009 and 2008, respectively.

13

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5Stock-based Compensation Plan (Continued)

Compensation expense charged against income for all stock-based awards during the six months ended June 30, 2009 and 2008 on a pre-tax basis was approximately
$1.4 million and $2.0 million, respectively, which is included in general and administrative expense in the Condensed Consolidated Statements of Operations.

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

For the Periods EndedJune 30, 2009

December 31, 2008Risk free rates


1.24 - 1.34
%

1.60 - 4.53
%Dividend yield


0
%

0
%Expected volatility


107.01 - 108.93
%

54.37 - 104.22
%Weighted average expected stock option life


2.97 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

$
0.77

$
1.08Total options granted


1,150,000


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

$
811,013

$
2,147,541


A
summary of the stock options outstanding as of June 30, 2009 is as follows:

Number
of Options

Weighted
Average
Exercise
PriceBalance outstanding at December 31, 2008


7,507,499

$
2.87Granted


1,150,000


1.18Canceled


(720,666
)

2.30Expired


(775,000
)

0.45Balance outstanding at June 30, 2009


7,161,833

$
2.92Options exercisable at June 30, 2009


4,279,000

$
3.44


14

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5Stock-based Compensation Plan (Continued)

At
June 30, 2009, stock options outstanding were as follows:

Exercise Price

Number of
Shares

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


930,500


6.98$1.01 - $2.00


2,000,000


3.34$2.01 - $3.00


350,000


7.82$3.01 - $4.00


2,226,333


4.28$4.01 - $5.00


190,000


1.99$5.01 - $6.26


1,465,000


7.907,161,833


5.22


The
aggregate intrinsic value of both outstanding and vested options as of June 30, 2009 was $552,495 based on the Company's June 30, 2009 closing common stock price of
$1.09 per share. The total grant date fair value of the shares vested during the six months ended June 30, 2009 was $1,888,019. As of June 30, 2009, there was $3,017,504 of total
unrecognized compensation cost related to unamortized options. That cost is expected to be recognized over a period of approximately three years.

As
of June 30, 2009, there were 30,000 unvested shares of restricted stock grants with a weighted-average grant date fair value of $3.69 per share. Total unrecognized compensation
cost of $84,723 related to non-vested restricted stock is expected to be recognized over a two-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 6Commitments and Contingencies

The Company leases office facilities under an operating lease agreement that expires on June 30, 2012. Rent expense was $104,409 and $148,778 for the six month periods ended
June 30, 2009 and 2008, respectively.

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

Years ending on December 31,2009


158,6722010


279,3072011


292,2172012


147,641Total

$
877,837


During
the second quarter of 2008, the Company entered into contracts for the use of two new-build drilling rigs. The first rig was placed into operation in November 2008 and
entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled. The Company intends to continue to utilize this rig in its drilling operations on the
FBIR. The estimated termination fee for the

15

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6Commitments and Contingencies (Continued)

first
rig is approximately $4.4 million as of June 30, 2009. Under the terms of the drilling rig contract for the second rig (the "Second Rig Contract"), the Company was initially
scheduled to take delivery of the second rig in February 2009 but, effective August 2009, the Company and the contractor have agreed to an amendment to the Second Rig Contract to defer such delivery.
(See Note 9Subsequent Events) Under the amendment, the Company will make monthly payments until the earlier of delivery of the second rig or the expiration of twelve months
totaling up to an aggregate of $1.9 million ("Delay Payments"). If the Company takes delivery of the second rig during this 12-month period, a portion of the Delay Payments may be
applied in the form of a credit against future operating charges incurred by the Company under the Second Rig Contract, which has a two-year drilling commitment. The actual amount of the
credit will decrease as time passes creating an incentive for the Company to take delivery or locate a party to assume the rig commitment. In the event that the Company does not take delivery of the
rig before the expiration of the 12-month period or cancels the Second Rig Contract after delivery, the Company may be required to pay a termination fee. The maximum termination fee
payable by the Company would be $5.6 million, against which, under certain circumstances, some or all of the Delay Payments may be applied in the form of a credit.

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 7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. 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

16

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7Credit Facility (Continued)

revolving
loan, together with any unpaid fees and expenses relating thereto, will be due and payable no later than September 11, 2010.

As
of June 30, 2009, we had no outstanding borrowings under the Credit Facility and we had $209,899 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 of the Credit Facility. The borrowing base is re-determined semi-annually in May and November. The May 2009 review was completed
during the second quarter of 2009 resulting in lowering the Company's borrowing base from $3.0 million to $1.95 million effective June 4, 2009. None of our recently completed and
producing wells located on the Fort Berthold Indian Reservation were included in the May 2009 borrowing base review. Subsequent to June 30, 2009, the company entered into an agreement to sell a
portion of one of its producing wells subject to the borrowing base (see note 9). Included in the transaction was a like interest in the HBU #5-3 well where our interest will be
reduced by 50% from 41.7082% NRI to 20.8541% NRI effective August 1, 2009. The Company anticipates that due to the reduction of our interest in the HBU #5-3 well, the borrowing base
will be further reduced to approximately $1.625 million. To date, we have never borrowed against our Credit Facility, and since June 30, 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. To date, we have not hedged any production and therefore, have
not utilized this Agreement.

Note 8Differences Between Canadian and United States Accounting Principles

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America which differ in certain respects with those
principles and practices that the Company would have followed had its financial statements been prepared in accordance with accounting principles and practices generally accepted in Canada. Management
does not believe its financial statements would vary materially had they been prepared in accordance with Canadian GAAP or that any recently issued, not yet effective, Canadian accounting standards if
currently adopted would have a material effect on the accompanying financial statements.

Note 9Subsequent Events

The Company entered into an agreement with a private company in July 2009, made effective as of June 30, 2009, to acquire an additional 31.25% working interest in the Company's
Tall Bear prospect area on the Fort Berthold Indian Reservation in Dunn County, North Dakota. Concurrently in July 2009, the Company entered into a separate agreement, made effective July 1,
2009, with a private industry partner whereby we agreed to convey certain of our leasehold to the joint venture partner resulting in a sell-down of 3,300 net acres to our leasehold in the
Charging Eagle and Tall Bear

17

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 9Subsequent Events (Continued)

prospects,
now referred to as the Twin Buttes area. In consideration, the agreement provided that we would receive $1.85 million cash, net of the costs to acquire the 31.25% working interest,
and the Company will pay 50% of the first five wells drilled in the Twin Buttes area for our 60% working interest, proportionally reduced. Both of these transactions closed in July 2009.

Effective
August 1, 2009, the Company entered into an amendment with Devon Energy Production Company, L.P. ("Devon"), a wholly owned subsidiary of Devon Energy Corp.
whereby the Company has assigned approximately 50% of its current interest in its Vermillion Basin prospect area in southwest Wyoming to Devon. In return, the Company will be carried for its remaining
25% working interest in two horizontal completions on wells that were drilled earlier, one located in the Coyote Flats Unit and the other located in the Horseshoe Basin Unit. Furthermore, the Company
will be relieved of all previously recorded indebtedness to Devon, for costs associated with exploration work that exceeded the $30 million carried interest previously disclosed. As of
June 30, 2009, the Company reflected a payable of approximately $1.4 million and an oil and gas sales receivable of approximately $400,000 that will be offset against each other and any
remaining accounts payable will be canceled. Therefore, as of August 1, 2009, neither party will have amounts due to nor due from the other party nor will the Company incur any further costs
through the completion, equipping or tying into sales of the two horizontal wells mentioned above.

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

18

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Table of Contents

ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

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

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

19

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Table of Contents

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.

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

20

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Table of Contents

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

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

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

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

Recent Developments

Williston Basin OperationsDunn County, North Dakota

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

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Table of Contents

Drilling and Completion Activity

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

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

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

Kodiak Oil & Gas Corp. Drilling and Completion ActivitiesWell

WI / NRI
(%)

Days to
TD*

Length of
Lateral

Completion
Date

Number
of Stages

IP 24-Hour
Test BOE/D

First 30 Day
Oil
Production

NoteMC #16-34-2H


60 /49


41


4,169'


4/23/2009


8


711


8,397

flowing wellMC #16-34H


60 / 49


36


4,150'


5/4/2009


5


1,394


13,406

flowing wellTSB #16-8-7H


37.5 / 30.5


28


8.995'


6/7/2009


15


1,856


21,542

flowing wellTSB #16-8-16H


50 /41


31


4,465'


6/18/2009


5


811


12,288

flowing wellTSB #14-33-28H


50 /41


31


8,313'


8/3/2009


15







CompletingTSB #14-33-6H


50 /41


26


4,163'


8/24/2009


6







CompletingCE #1-22-10H


55 /45





**9,000'













DrillingCE #1-22-23H


60 /50





**5,000'













Spud after CE#1-22-10HTB #16-15-10H


60 /50





**9,000'













Spud after CE#1-22-23H


---

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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Table of Contents

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

For the three months ended

For the six months endedJune 30, 2009

June 30, 2008

June 30, 2009

June 30, 2008Sales Volume:Gas (Mcf)


58,878


36,108


158,572


102,708Oil (Bbls)


35,314


13,010


51,800


28,858Production volumes (BOE)


45,127


19,028


78,229


45,976Price:Gas ($/Mcf)

$
2.20

$
12.80

$
2.60

$
9.04Oil ($/Bbls)

$
52.69

$
115.42

$
45.48

$
100.97Production costs ($/BOE):Lease operating expenses

$
2.37

$
54.75

$
3.12

$
39.94Production and property taxes

$
4.88

$
11.23

$
2.48

$
8.09Gathering, Transportation & & Marketing

$
0.36

$
1.40

$
0.69

$
1.24


Results of Operations

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

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

23

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Table of Contents

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

For the three months endedJune 30, 2009

June 30, 2008Financial ResultsTotal revenue

$
2,013,030

$
2,000,690Total costs and expenses

$
2,551,184


3,899,131Net loss

$
(538,154
)
$
(1,898,441
)Diluted net loss per common share

$
(0.01
)
$
(0.02
)Capital Resources and LiquidityCash and cash equivalents at end of the period

$
3,821,907

$
1,199,427Net cash provided by (used in) operating activities

$
1,779,759

$
(2,741,050
)Capital expendituresoil and gas properties excluding accruals and proceeds from divestitures

$
5,590,294

$
6,042,791Adjusted EBITDA (see below discussion)

$
582,702

$
(664,735
)


Oil and Gas Revenue and Production

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

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of $343,674 during the three month period ended
June 30, 2009, as compared to $1,282,618 during the same period in 2008. In the second quarter of 2008, we performed workover operations on our producing Bakken oil wells in McKenzie County,
N.D. The net cost of approximately $1.0 million related to the repair work was charged to oil and gas production costs and expenses in the second quarter of 2008. Excluding workover operations
but including both lease operating and production tax expense, our lease operating costs increased by approximately $61,000 for the three month period ended June 30, 2009, as compared to the
same period in 2008. The increase is attributed to new wells in production during the second quarter of 2009 as compared to the second quarter of 2008.

Depletion, Depreciation and Amortization

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

24

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Table of Contents

Ceiling Test Impairment

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

General and Administrative Expense

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

EBITDA

In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gains or losses on
foreign currency exchange, non-cash stock-based compensation expense, impairment expense and accretion of abandonment liability ("Adjusted EBITDA") as a key indicator of financial operating
performance and as a measure of the ability to generate cash for operational activities, future capital expenditures and servicing of borrowings under the Company's Credit Facility. The Company's
Adjusted EBITDA increased by approximately $1.3 million to approximately $0.6 million for the three months ended June 30, 2009 from the same period in 2008. The increase in
Adjusted EBITDA was primarily the result of the increase in both oil and natural gas production during the period as compared to the same period in 2008. Adjusted EBITDA is not a Generally Accepted
Accounting Principle ("GAAP") measure of performance. The Company uses this non-GAAP measure primarily to compare its performance with other companies in the industry that make a similar
disclosure and as a measure of its current liquidity. The Company believes that this measure may also be useful to investors for the same purpose and for an indication of the Company's ability to
generate cash flow at a level that can sustain or support our operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for operating income
or loss, cash flow from operations determined under GAAP or any other measure for determining the Company's operating performance that is calculated in accordance with GAAP. In addition, because
Adjusted EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled

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

Three months ended
June 30, 2009

Three months ended
June 30, 2008Reconciliation of Adjusted EBITDA:Net Loss

$
(538,154
)
$
(1,898,441
)Add back:Depreciation, depletion, amortization and accretion


532,454


786,777(Gain) / loss on foreign currency exchange


(5,288
)

(1,772
)Stock based compensation expense


593,690


448,701Adjusted EBITDA

$
582,702

$
(664,735
)


Results of Operations

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

The Company's net loss for the six months ended June 30, 2009 of $2.2 million, improved from a net loss of
$4.5 million for the same period in 2008. This improvement in net income is primarily attributable to new production from our FBIR wells, which began production in the second quarter of 2009,
and from new wells coming on to production in late 2008 in our Vermillion Basin area. Additionally, we had production from our existing wells during the six month period in 2009 that were
shut-in for workover activities in the second quarter of 2008. For the six month periods ended June 30, 2008 and 2009, our volumes on a BOE basis, increased by 70% from 45,976 BOE
to 78,229 BOE. This increase in volumes was however offset by lower oil and natural gas pricing realized during the six month period ended June 30, 2009 versus the six month period ended
June 30, 2008. Total natural gas price realizations decreased 71% to $2.60 per Mcf for the six month period ended June 30, 2009, compared to $9.04 per Mcf for the same period in 2008.
Oil price realizations declined by 55% to $45.48 per barrel for the three month period ended June 30, 2009, compared to $100.97 per barrel for the same period in 2008. Although we had an
increase in production for the period, lower pricing for both oil and natural gas offset our increased production, resulting in total revenue that was approximately $1.1 million less during the
six month period ended 2009 compared to the same period in 2008.

For the six months endedJune 30, 2009

June 30, 2008Financial ResultsTotal revenue

$
2,804,389

$
3,962,227Total costs and expenses


4,970,150


8,492,704Net loss

$
(2,165,761
)
$
(4,530,477
)Diluted net loss per common share

$
(0.02
)
$
(0.05
)Capital Resources and LiquidityCash and cash equivalents at end of the period

$
3,821,907

$
1,199,427Net cash provided by (used in) operating activities

$
(693,632
)
$
(5,169,992
)Capital expendituresoil and gas properties excluding accruals and proceeds from divestitures

$
9,407,721

$
9,171,252Adjusted EBITDA (see below discussion)

$
90,971

$
(662,382
)


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Oil and Gas Revenue and Production

During the six-month period ended June 30, 2009, as compared to the same period in 2008, natural gas production
volumes increased 54% due to production from wells shut-in for workover operations in 2008 that are now producing and from new production which came on-line in the fourth
quarter of 2008, while crude oil production volumes increased 79% due to new production coming on-line during May and June of 2009 from completion operations in our FBIR area. Total gas
price realizations decreased 71% to $2.60 per Mcf for the six month period ended June 30, 2009, compared to $9.04 per Mcf for the same period in 2008. Oil price realizations declined by 55% to
$45.48 per barrel for the six month period ended June 30, 2009, compared to $100.97 for the same period in 2008. Primarily due to the decline in both oil and natural gas pricing, total revenues
declined by $1.1 million to $2.8 million for the six month period ended June 30, 2009, compared to the same period in 2008.

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of $492,203 during the six month period ended June 30,
2009, as compared to $2,265,569 during the same period in 2008. In the first half of 2008, we performed workover operations on our producing Bakken oil wells in McKenzie County, ND. The net cost of
approximately $1.4 million related to the repair work was charged to oil and gas production costs and expenses in the first half of 2008. Excluding workover operations but including both lease
operating and production tax expense, our lease operating costs decreased by approximately $373,000 for the six month period ended June 30, 2009, as compared to the same period in 2008. We have
shut in certain oil and gas wells due to low commodity prices which rendered the wells non-commercial, which reduced our lease operating expense during the period. In addition, early in
2009, the Company reconciled and recorded outstanding ad valorem tax accruals resulting in a credit of approximately $93,000.

Depletion, Depreciation and Amortization

Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was $887,794 for the six month period ended
June 30, 2009, compared to $1,884,076 for the same period in 2008. DD&A expense decreased during the first half of 2009 due to the impairment charges taken in 2008 which reduced the full cost
pool by $47.5 million year over year thereby decreasing the DD&A expense recorded.

Ceiling Test Impairment

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

General and Administrative Expense

The Company's general and administrative costs were approximately $3.6 million for the six months ended June 30, 2009
compared to approximately $4.3 million for the same period in 2008. This 17% reduction for the period is primarily due to an ongoing effort to reduce general and administrative costs
company-wide. Excluding the non-cash stock-based compensation expense in each period, due to our ongoing cost containment efforts, our general and administrative costs related
to employee costs, travel, legal and consulting expenses declined by approximately $138,000 or 6% during the first half of 2009 as compared to the same period in 2008. In addition, we recorded lower
stock-based

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compensation
expense of approximately $1.4 million for the six months ended June 30, 2009 compared to $2.0 million recorded for the same period in 2008, related to options and
restricted stock issued to officers, directors and employees. The reduction in the stock-based compensation expense is due to the reversal recorded as of June 30, 2009, of
non-vested performance based stock options that expired as of March 20, 2009. Stock-based compensation expense related to the expired performance based stock options was
approximately $122,000.

EBITDA

In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gains or losses on
foreign currency exchange, non-cash stock-based compensation expense, impairment expense and accretion of abandonment liability ("Adjusted EBITDA") as a key indicator of financial operating
performance and as a measure of the ability to generate cash for operational activities, future capital expenditures and servicing of borrowings under the Company's Credit Facility. The Company's
Adjusted EBITDA increased by approximately $753,000 to approximately $91,000 thousand for the six months ended June 30, 2009 from the same period in 2008. The increase in Adjusted EBITDA
was primarily the result of the increase in both oil and natural gas production during the period as compared to the same period in 2008 Adjusted EBITDA is not a Generally Accepted Accounting
Principle ("GAAP") measure of performance. The Company uses this non-GAAP measure primarily to compare its performance with other companies in the industry that make a similar disclosure
and as a measure of its current liquidity. The Company believes that this measure may also be useful to investors for the same purpose and for an indication of the Company's ability to generate cash
flow at a level that can sustain or support our operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for operating income or loss, cash
flow from operations determined under GAAP or any other measure for determining the Company's operating performance that is calculated in accordance with GAAP. In addition, because Adjusted EBITDA is
not a GAAP measure, it may not necessarily be comparable to
similarly titled measures employed by other companies. A reconciliation of Adjusted EBITDA and net income for the six months ended June 30, 2009 and 2008 is provided in the table below:

Year-to-date
June 30,
2009

Year-to-date
June 30,
2008Reconciliation of Adjusted EBITDA:Net Loss

$
(2,165,761
)
$
(4,530,477
)Add back:Depreciation, depletion, amortization and accretion


887,794


1,884,076(Gain) / loss on foreign currency exchange


(6,142
)

16,508Stock based compensation expense


1,375,080


1,967,511Adjusted EBITDA

$
90,971

$
(662,382
)


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Liquidity and Capital Resources

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

For the three months
ended June 30,

For the six months
ended June 30,2009

2008

2009

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

$
3,821,907

$
1,199,427

$
3,821,907

$
1,199,427Net cash provided by (used in) operating activities


1,779,759


(2,741,050
)

(693,632
)

(5,169,992
)Net cash used in investing activities


(7,057,450
)

(6,042,292
)

(10,157,901
)

(6,724,649
)Net cash provided by financing activities


7,092,175


78,750


7,092,175


78,750Net cash flow


1,814,484


(8,704,592
)

(3,759,358
)

(11,815,891
)


Kodiak
ended the second quarter of 2009 with cash and cash equivalents of approximately $3.8 million as compared to approximately $7.6 million at year-end 2008.
Total working capital was approximately $10.3 million at June 30, 2009, as compared to approximately $15.4 million at December 31, 2008. As operator of our current activity
in the Williston Basin we must place orders and take delivery of tubular goods in advance of actual drilling in order to assure availability of the tubular goods. With the current level of drilling
activity and requirements for tubular goods, it is anticipated that the prepaid amount will remain at a relatively constant level from period to period. As wells are drilled these tubular goods become
part of our cost of wells, whereby our working interest share is already paid while the portion related to other working interest partners is recovered through our joint interest billings. As of
June 30, 2009, we had prepaid $7.5 million towards the cost of tubular goods ($6.0 million of tubular goods that are inventoried in third party yards and $1.5 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 of
$2.2 million from December 31, 2008 to June 30, 2009,
approximately $4.3 million of prepaid tubular goods were used in operations ($2.2 million billed to working interest partners) and we took delivery of an additional $3.1 million
of tubular goods of which we had made previous deposits of $1.0 million, therefore reducing our deposit balance to $1.5 million. Net cash flow used in operating activities for the first
half of 2009 was $0.6 million. Net cash used as investing activities (which includes recoupments from partners and restricted cash changes) totaled $10.2 million for the first half of
2009. These investing items were comprised of $11.5 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 $9.4 million for the first half of 2009. In May 2009, we issued 9.6 million common shares to
certain institutional investors in a non-brokered registered direct offering, realizing net cash of $7.1 million provided by financing activities.

Our
results of operations and financial condition are significantly affected by the success of our exploration and land leasing activity, the resulting production and reserves, oil and
natural gas commodity prices and the costs related to operating our properties. In the first half of 2009, our oil and natural gas revenue decreased by 28% from $3.8 million as of
June 30, 2008 to $2.8 million as of June 30, 2009. This decrease is largely the result of the decrease in crude oil and natural gas pricing realized during the first half of 2009
as compared to the first half of 2008. Total costs and expenses decreased to $4.9 million for the first half of 2009 from $8.5 million for the first half of 2008. This decline is largely
due to workover expenses of $1.4 million incurred in 2008 which did not occur in 2009, a decrease in general and administrative expenses which included a decrease in the non-cash
charge for stock based compensation due to a reversal of non-vested performance based options during

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the
first half of 2009 of approximately $122,000 and lower stock-based compensation expense caused by a lower exercise price at which options were issued in the first half of 2009 as compared to the
same period in 2008.

During
the first six months of 2009, we incurred capital expenditures of approximately $11.5 million. We initially anticipated total net capital expenditures of up to
$15.3 million in 2009, compared to approximately $11.0 million incurred in 2008. We continue to evaluate and monitor our capital expenditures in relation to commodity prices. As oil
prices have improved since the beginning of the year and drilling costs have declined during this same period, we have continued to drill and complete wells in the Williston Basin. At this time we
anticipate that we will continue those operations through year end and the $4.0 million of capital expenditures initially projected for the Vermillion Basin will be reallocated to the Williston
Basin where our capital expenditures for the year are expected to be approximately $21.0 million. Such estimate does not include any potential costs or fees associated with the second drill
rig.

In
a further attempt to maintain adequate capital, and retain a 50-60% working interest in wells, we sold an interest in a portion of our lands on the FBIR in July 2009
whereby Kodiak realized $1.85 million in cash (after netting the costs associated with acquiring the 31.25% working interest in the Tall Bear prospect area) and a carried working interest in
five wells, three which are expected to be drilled in 2009. Additionally we are anticipating drilling one or two wells on acreage
that was part of an exploration agreement whereby Kodiak would pay 20% of the costs for its 60% working interest thereby reducing Kodiak's share of the drilling costs.

Based
upon our current working capital, current costs of drilling and completing wells, and current level of working interest, combined with our growing cashflow from production, we
anticipate that we have the financial means to continue drilling and completion operations on the FBIR into the first part of 2010.

The
following tables set forth our capital expenditures for the six months ended June 30, 2009 and our maximum planned capital expenditures for our principal properties in 2009.
Net capital expenditures include both cash expenditures and accrued expenditures and are net of proceeds from divestitures.

Project Location

Net Capital
Expenditures(1)
For the Six
Months Ended
June 30, 2009
($000)

Initial 2009
Budgeted Net
Capital
Expenditures(1)
($000)

Revised 2009
Budgeted Net
Capital
Expenditures(1)
($000)Williston BasinMission Canyon/Red River wells and related infrastructure





700


700Bakken wells and related infrastructure


10,337


10,055


19,555Acreage/Seismic


1,045


500


500Total Williston Basin

$
11,382

$
11,255

$
20,755WyomingVermillion Basin wells and related infrastructure

$
81

$
4,000

$
150Acreage/Seismic


29





Total Wyoming

$
110

$
4,000

$
150Total All Areas

$
11,492

$
15,255

$
20,905


---

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Oil and Gas Properties

As of June 30, 2009, we had several hundred lease agreements representing approximately 165,000 gross and 98,000 net acres,
primarily in the Green River and Williston Basins.

As
discussed above, effective June 30, 2009, we entered into an agreement to acquire an additional 31.25% working interest in the Tall Bear prospect area. Separately and
concurrently, we entered into a separate agreement, effective July 1, 2009, with a private industry partner whereby we agreed to convey certain leaseholds within our Charging Eagle and Tall
Bear prospects to a joint venture partner. The effect of these two agreements resulted in a reduction of 3,300 net acres to our leasehold in the Charging Eagle and Tall Bear prospects, which we now
refer to as the Twin Buttes area as of July 1, 2009.

As
of June 30, 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. We operate all of our
leasehold on the reservation excepting an approximate 7,000 net acres that are in a participating area previously established with another operator. 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 June 30, 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 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 June 30, 2009.

Undeveloped
Acreage(1)

Developed
Acreage(2)

Total AcreageGross

Net

Gross

Net

Gross

NetGreen River BasinWyoming(3)


42,702


17,435


1,520


908


44,222


18,343Colorado


7,419


4,986


0


0


7,419


4,986Williston BasinMontana


31,794


19,090


800


400


32,594


19,490North Dakota


63,503


41,788


4,640


2,584


68,143


44,372Other BasinsWyoming


12,562


10,875


0


0


12,562


10,875Acreage Totals


157,980


94,174


6,960


3,892


164,940


98,066


---

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

31

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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
June 30, 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.

Recently Issued Accounting Pronouncements

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.

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 became effective November 15, 2008. In June 2009, the FASB issued
Statement of Financial Accounting Standards No. 168,The FASB Accounting Standards Codification

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("SFAS 168").
SFAS 168 will become the source of authoritative U.S. GAAP recognized by the FASB, effectively superseding SFAS 162. SFAS 168 is effective for interim
and annual reporting periods ending after September 15, 2009. The adoption of SFAS 168 will not have a material impact on the Company's financial position or results of operations.

In
May 2009, the FASB issued Statement of Financial Accounting Standards No. 165,Subsequent Events("SFAS 165").
SFAS 165 provides guidance for management's assessment of subsequent events. An additional disclosure required by SFAS 165 is to identify the 'as of' date of the subsequent event.
SFAS 165 is effective for interim and annual reporting periods ending after June 15, 2009. The adoption of SFAS 165 did not have a material impact on the Company's financial
position or results of operations.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and Gas Price Fluctuations

Our primary market risk is market changes in oil and natural gas prices. Prospective revenues from the sale of products or properties
will be impacted by oil and natural gas prices. A $1.00 per Mcf change in the market price of natural gas will result in an approximate $58,878 change in our gross gas production revenue. A $1.00 per
barrel change in the market price of oil will result in an approximate $35,314 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
$51,289 annual impact if all of our cash, as of June 30, 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 June 30, 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

We may incur termination fees related to two drilling rig contracts that we entered into in 2008 which could impair our working capital.

During the second quarter of 2008, we entered into contracts for the use of two new-build drilling rigs. The first rig was
placed into operation in November 2008 and entails a two-year drilling commitment and specific termination fees if drilling activity is cancelled or never commenced. The estimated
termination fee for the first rig is approximately $4.4 million as of June 30, 2009. Under the terms of the Second Rig Contract, we were initially scheduled to take delivery of the
second rig in February 2009 but, effective August 2009, the Company and the contractor have agreed to an amendment to the Second Rig Contract to defer such delivery. Under the amendment, the Company
will make monthly Delay Payments until the earlier of delivery of the second rig or the expiration of twelve months totaling up to an aggregate of $1.9 million. If we take delivery of the
second rig during this 12-month period, a portion of the Delay Payments may be applied in the form of a credit against future operating charges incurred by the Company under the Second Rig
Contract, which has a two-year drilling commitment. The actual amount of the credit will decrease as time passes creating an incentive for the Company to take delivery or locate a party to
assume the rig commitment. In the event that the Company does not take delivery of the rig before the expiration of the 12-month period or cancels the Second Rig Contract after delivery,
the Company may be required to pay a termination fee. The maximum termination fee payable by the Company would be $5.6 million, against which, under certain
circumstances, some or all of the Delay Payments may be applied in the form of a credit. 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.

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

None.

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

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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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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.August 6, 2009



/s/ LYNN A. PETERSON Lynn A. Peterson President and Chief Executive OfficerAugust 6, 2009



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


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