Table of Contents



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

FORM 10-Q

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

For the quarterly period ended September 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

118,779,931 shares, no par value, of the Registrant's Common Stock were issued and outstanding as of November 5, 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

17ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

31ITEM 4.

CONTROLS AND PROCEDURES

31PART IIOTHER INFORMATION

32ITEM 1.

LEGAL PROCEEDINGS

32ITEM 1A.

RISK FACTORS

32ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

32ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

32ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

32ITEM 5.

OTHER INFORMATION

32ITEM 6.

EXHIBITS

33SIGNATURES

34


1

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Table of Contents

PART 1FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)
September 30,
2009

December 31,
2008ASSETSCurrent Assets:Cash and cash equivalents

$
1,754,518

$
7,581,265Accounts receivableTrade


3,840,232


1,934,818Accrued sales revenues


2,020,757


516,870Prepaid expenses and other


7,428,725


10,621,980Total Current Assets


15,044,232


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


113,057,019


97,934,058Unproved oil and gas properties


11,721,677


11,985,533Wells in progress


4,703,767


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


(94,604,702
)

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


34,877,761


17,842,773Other property and equipment, net of accumulated depreciation of $265,776 in 2009 and $270,620 in 2008


288,072


272,705Restricted investments





246,068Total Assets

$
50,210,065

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

$
7,595,552

$
4,125,335Advances from joint interest owners


1,307,484


1,105,740Total Current Liabilities


8,903,036


5,231,075Noncurrent Liabilities:Asset retirement obligation


1,034,000


787,180Total Liabilities


9,937,036


6,018,255Commitments and ContingenciesNote 6Stockholders' Equity:Common stockno par value; unlimited authorizedIssued and outstanding: 104,979,931 shares in 2009 and 95,129,431 shares in 2008Contributed surplus


145,747,452


136,297,845Accumulated deficit


(105,474,423
)

(103,299,621
)Total Stockholders' Equity


40,273,029


32,998,224Total Liabilities and Stockholders' Equity

$
50,210,065

$
39,016,479


SEE
ACCOMPANYING NOTES

2

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Table of Contents

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

Three months ended September 30,

For the Nine Months Ended September 30,2009

2008

2009

2008Revenues:Gas production

$
129,454

$
149,804

$
541,257

$
1,077,887Oil production


3,602,704


1,594,080


5,958,771


4,507,974Interest & other


7,171


38,467


43,691


158,717Total revenue


3,739,329


1,782,351


6,543,719


5,744,578Cost and expenses:Oil and gas production


740,185


856,398


1,232,389


3,121,967Depletion, depreciation, amortizationand accretion


1,050,481


1,220,222


1,938,275


3,104,298Asset impairment





15,500,000





15,500,000General and administrative


1,962,087


2,162,388


5,558,382


6,488,938(Gain)/loss on currency exchange


(4,384
)

2,992


(10,526
)

19,501Total costs and expenses


3,748,369


19,742,000


8,718,520


28,234,704Net loss

$
(9,040
)
$
(17,959,649
)
$
(2,174,801
)
$
(22,490,126
)Basic & diluted weighted-average common shares outstanding


104,832,898


91,742,529


100,101,589


89,265,263Basic & diluted net loss per common share

$
(0.00
)
$
(0.20
)
$
(0.02
)
$
(0.25
)


SEE
ACCOMPANYING NOTES

3

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Table of Contents

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

Nine Months Ended September 30,2009

2008Cash flows from operating activities:Net loss

$
(2,174,801
)
$
(22,490,126
)Reconciliation of net loss to net cash (used in) provided by operating activities:Depletion, depreciation, amortization and accretion


1,938,275


3,104,298Asset impairment





15,500,000Stock based compensation


2,146,983


2,742,312Changes in current assets and liabilities:Accounts receivable-trade


(1,905,414
)

(736,751
)Accounts receivable-accrued sales revenue


(1,503,887
)

27,572Prepaid expenses and other


2,807,942


6,524Accounts payable and accrued liabilities


3,749,090


(1,267,033
)Net cash provided by (used in) operating activities


5,058,188


(3,113,204
)Cash flows from investing activities:Oil and gas properties


(18,778,013
)

(11,930,131
)Sale of oil and gas properties


3,250,000


2,437,892Equipment


8,000


(19,846
)Prepaid tubular goods


(2,928,615
)

(6,859,918
)Restricted investment: undesignated as restricted


246,068


10,329Net cash (used in) investing activities


(18,202,560
)

(16,361,674
)Cash flows from financing activity:Proceeds from the issuance of shares


7,425,450


18,935,000Issuance costs


(107,825
)

(1,283,512
)Net cash provided by financing activities


7,317,625


17,651,488Net change in cash and cash equivalents


(5,826,747
)

(1,823,390
)Cash and cash equivalents at beginning of the period


7,581,265


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

$
1,754,518

$
11,191,928Supplemental cash flow informationOil & gas property accrual included inAccounts payable and accrued liabilities

$
1,380,060

$
47,500Asset retirement obligation

$
175,047

$
(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.

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.

5

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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 September 30, 2009 we had approximately $7.3 million (consisting of $6.8 million of tubular goods and surface equipment that are inventoried in third-party
yards and $0.5 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 $0.5 million tubular goods deposit, as of
September 30, 2009, the Company estimates that an additional $1.1 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 September 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

Due to the Company's credit facility (see Note 7), we are no longer required to maintain restricted investments as security for
our 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 has, on an ongoing basis, balances in excess of the federally insured limits.

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

Oil and Gas Producing Activities

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and
development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying
charges on non-producing properties, costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost
pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant
alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

Depletion
of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated
proved oil and gas reserves as

6

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

determined
by the Company's engineers and audited (annually) by independent petroleum engineers. Costs included in the depletion base to be amortized include (a) all proved capitalized costs
including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and
(c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset
retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are
reviewed quarterly for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to
depletion calculations. During the nine months ended September 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 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

7

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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)

feet
of natural gas to one barrel of crude oil. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not
exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization
(without regard to estimates of fair value), or estimated fair value, if lower of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment is
recognized. The present value of estimated future net revenues is computed by applying current prices of oil and gas to estimated future production of proved oil and gas reserves as of
period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions.

There
were no impairment charges recognized for the nine month period ended September 30, 2009. 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, inclusive of a $15.5 million impairment expense recorded in
the quarter ended September 30, 2008.

Wells in Progress

Wells
in progress at September 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. At September 30,
2009, the Company had three wells waiting completion in its Bakken oil play on the Forth Berthold Indian Reservation ("FBIR') and four wells waiting completion on its Vermillion Basin prospect.

Impairment of Long-lived Assets

The Company's unproved properties are evaluated quarterly for the possibility of impairment. In the nine months ended
September 30, 2009 no unproved properties were impaired. For the nine months ended September 30, 2008, the Company recorded an impairment expense of $15.5 million.

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 $19,116 in the nine month period ended
September 30, 2009.

8

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Other Property and Equipment

Other property and equipment, such as office furniture and equipment, vehicles and computer hardware and software, are recorded at
cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is recorded
using the straight-line method over the estimated useful lives of three years for computer equipment, and five years for office equipment and vehicles. When other property and equipment is
sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

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 September 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 September 30, 2009, and December 31, 2008, the Company has recorded a net asset of $620,974 and
$501,900 and a related

9

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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)

liability
of $1,034,000 and $787,180, respectively. The information below reconciles the value of the asset retirement obligation for the periods presented.

For the Period EndedSeptember 30, 2009

December 31, 2008Balance beginning of period

$
787,180

$
874,498Liabilities incurred


175,047


Liabilities settled





(147,252
)Accretion expense


71,773


59,934Balance end of period

$
1,034,000

$
787,180


Off Balance Sheet Arrangements

On September 14, 2009, the Company entered into an amendment (the "Amendment") to the drilling rig contract in respect of one of
its two drilling rigs (the "Second Rig"). Under the terms of the original drilling rig contract (the "Original Second Rig Contract"), which has a two-year drilling commitment, the Company
was scheduled to take delivery of the Second Rig in February 2009. In consideration of such deferral, pursuant to the Amendment, the Company has agreed to make monthly payments until the earlier of
delivery of the Second Rig or the expiration of 12 months (the "Delay Payments"). If the Company does not accept delivery of the Second Rig, the aggregate amount of the Delay Payments will be
$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 Original Second Rig Contract. 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.

Other
than standard operating leases and our drilling rig commitments, as amended, the Company did not have any other off balance sheet financing arrangements at September 30,
2009 and December 31, 2008.

Recently Adopted Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board ("FASB") issuedThe FASB Accounting Standards
Codification("ASC') which became effective for interim and annual reporting periods ending after September 15, 2009. The Codification is the source of authoritative
U.S. GAAP recognized by the FASB. The adoption of the Codification did not have a material impact on the Company's financial position or results of operations.

In
December 2007, the FASB issued a pronouncement regarding business combinations ("ASC 805"). This pronouncement is effective for the Company's financial statements issued after
January 1, 2009. Under previous pronouncements, organizations utilized the announcement date as the measurement date for the purchase price of the acquired entity. ASC 805 requires measurement
at the date the acquirer obtains control of the acquiree, generally referred to as the acquisition date. ASC 805 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 ASC 805, adjustments to the acquired entity's deferred tax assets and
uncertain tax position balances

10

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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)

occurring
outside the measurement period are recorded as a component of the income tax expense, rather than goodwill. As the provisions of ASC 805 are applied prospectively, the impact to the Company
cannot be determined until the transactions occur.

In
May 2009, the FASB issued a pronouncement regarding subsequent events ("ASC 855"). ASC 855 provides guidance for management's assessment of subsequent events. An additional disclosure
required by ASC 855 is to identify the 'as of' date of the subsequent event. ASC 855 is effective for interim and annual reporting periods ending after June 15, 2009. The adoption of ASC 855
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. 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.

Note 3Wells in Progress

The following table reflects the net changes in capitalized additions to wells in progress during the nine months ended September 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. At September 30, 2009, the Company had three wells waiting completion in its
Bakken oil play on the FBIR and four wells waiting completion on its Vermillion Basin prospect. The three wells in the Bakken oil play are anticipated to be completed during the fourth quarter of
2009. One well in the Vermillion Basin is currently engaged in completions operations.

For the Nine
Months Ended
September 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


13,607,958


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


(9,632,284
)

(414,074
)Ending balance

$
4,703,767

$
728,093


11

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4Common Stock

In May 2009, the Company 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. The Company paid $107,825 in expenses related
to the offering. The net proceeds were used principally 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.

In
October 2009, the Company issued 13.8 million shares of common stock in a public offering (see Note 9) for gross proceeds of approximately $30.3 million. The
proceeds will be used principally for drilling and completion activities on the Company's leases in the Bakken oil play located on the FBIR 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 a stock price of $1.18 per share and 1,606,000 stock options at a stock price of $2.65 per share during the nine month periods ended September 30,
2009 and 2008, respectively.

Compensation
expense charged against income for all stock-based awards during the nine months ended September 30, 2009 and 2008 on a pre-tax basis was approximately
$2.1 million and $2.7 million, respectively, which is included in general and administrative expense in the Condensed Consolidated Statements of Operations.

12

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5Stock-based Compensation Plan (Continued)

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 EndedSeptember 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 September 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
)

0.45Exercised


(250,500
)

0.90Balance outstanding at September 30, 2009


6,911,333

$
2.99Options exercisable at September 30, 2009


4,257,000

$
3.62


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

Exercise Price

Number of Shares

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


680,000


9.21$1.01 - $2.00


2,000,000


3.05$2.01 - $3.00


350,000


7.53$3.01 - $4.00


2,226,333


3.99$4.01 - $5.00


190,000


1.70$5.01 - $6.26


1,465,000


7.616,911,333


5.11


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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5Stock-based Compensation Plan (Continued)

The
aggregate intrinsic value of both outstanding and vested options as of September 30, 2009 was $3,966,700 based on the Company's September 30, 2009 closing common stock
price of $2.40 per share. The total grant date fair value of the shares vested during the nine months ended September 30, 2009 was $2,431,654. As of September 30, 2009, there was
$2,306,974 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 September 30, 2009, there were 23,000 unvested shares of restricted stock grants with a weighted-average grant date fair value of $3.69 per share. Total unrecognized
compensation cost of $70,761 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 $186,131 and $207,105 for the nine month periods ended
September 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


69,2332010


279,3072011


292,2172012


147,641Total

$
788,398


During
the second quarter of 2008, the Company entered into contracts for the use of two new-build drilling rigs. The first rig was placed into operation in November 2008 and
entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior to September 15, 2010. The Company intends to continue to utilize this
rig in its drilling operations on the FBIR. The estimated termination fee for the first rig is approximately $4.0 million as of September 30, 2009. Under the terms of the Original Second
Rig Contract, the Company was initially scheduled to take delivery of the Second Rig in February 2009. However, effective August 2009, the Company and the contractor have agreed to an amendment to the
Original Second Rig Contract to defer such delivery. Under the amendment, the Company will make 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 Original 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 Second Rig
before the expiration of the 12-month period or cancels the Original Second Rig Contract after delivery, the Company may be required to pay a termination fee under the Original

14

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6Commitments and Contingencies (Continued)

Second
Rig Contract. The maximum termination fee payable by the Company would be $5.6 million, against which all of the Delay Payments would 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 meet 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 located outside the boundaries of the FBIR. The Credit Facility also provides for letters of credit that may be used for general
corporate purposes. Our aggregate borrowings and outstanding letters of credit under the Credit Facility may not, at any time, exceed the borrowing base. Interest on borrowings under the Credit
Facility accrues at variable interest rates, at our election, at either:



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

As
of September 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 November 2009 review was
completed in October 2009. Effective November 1, 2009 the borrowing base is $1.625 million. To date, we have never borrowed against our Credit Facility, and since September 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

15

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7Credit Facility (Continued)

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 Event

In October 2009, the Company issued 13,800,000 shares of common stock in a public offering for gross proceeds of $30,360,000. 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 Company estimates expenses of $1,718,000 will be paid related to the offering resulting in net proceeds of $28,642,000. The net proceeds will be used principally for drilling and completion
activities on the Company's leases in the Bakken oil play and for other general corporate activities.

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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 our Quarterly Reports on Form 10-Q 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 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.

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Table of Contents

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

Overview

Kodiak Oil & Gas Corp. ("Kodiak," "we" or the "Company") is an independent energy company focused on the exploration,
exploitation, acquisition and production of natural gas and crude oil in the United States. Our oil and natural gas reserves and operations are primarily concentrated in two Rocky Mountain basins, the
Williston Basin of North Dakota and Montana and the Green River Basin of Wyoming and Colorado. Kodiak's corporate strategy is to internally identify prospects, acquire lands encompassing those
prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved
reserves, as well as development and exploratory drilling opportunities on high potential conventional and non-conventional oil and natural gas prospects that we have the opportunity to
explore, drill and develop. Significant prospects in our portfolio currently include the following:





18

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Table of Contents

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
October 2009, we issued 13.8 million shares of common stock in a public offering for gross proceeds of approximately $30.3 million. 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. We estimate that expenses of $1.7 million will be paid related to the offering, resulting in net proceeds of $28.6 million.

The
proceeds from this offering will be used principally to fund the exploration and development of our acreage within the FBIR in Dunn County, North Dakota and for other general
corporate activities. We currently have 16 well bore permits (eight drilling pads) approved by the Bureau of Indians Affairs and the Bureau of Land Management, including the two Moccasin Creek wells,
which are expected to be spud in 2009. With these permits, we have developed a preliminary 2010 drilling program of ten to twelve gross wells, or five to six net wells, utilizing our existing drilling
rig. Additionally, we have been advised by our joint venture partner that exploration efforts on the non-operated portion of our leasehold are expected to begin in the second quarter of
2010. If our joint venture partner commences drilling activity in 2010, we anticipate that we may participate in as many as 17 to 20 gross wells, or approximately nine to 11 net wells, during 2010.
Over the next several months, after we complete the analysis of oil and gas production from the recently completed Charging Eagle wells and the Tall Bear well that has been drilled but not completed,
we will consider a second Kodiak-operated rig to develop the Twin Buttes Federal Unit. The Twin Buttes Federal Unit is geographically separated from our northwestern and western core operating areas
by the Little Missouri River making rig mobilizations and demobilizations more capital intensive. We anticipate that the net proceeds from the offering, together with cash generated from anticipated
production, will be sufficient to support our planned oil and natural gas exploration program through the end of 2010. If we realize lower than expected cash flow from production, either due to lower
than anticipated production levels or a decline in commodity prices from recent levels, we would need to curtail our planned exploration activity or seek alternative sources of capital, including by
means of entering into joint ventures with other exploration and production companies, sales of interests in certain of our properties or by undertaking additional financing activities, which may not
be available in amounts or on terms acceptable to us, if at all.

Recent Developments

Completion Activities

Our Charging Eagle CE #1-22-10H well, a 9,949 foot horizontal lateral, was recently successfully
completed in 15 stages. The well recorded initial 24-hour production rates of 1,288 barrels of oil equivalent per day, comprised of 1,187 barrels of oil per day and 606 thousand
cubic feet of natural gas per day. We operate the CE #1-22-10H well with a 55% working interest and a 45% net revenue interest.

The
CE #1-22-23H well, a shorter 6,620 foot horizontal lateral, was recently successfully completed in 13 stages. The well recorded initial 24-hour
production rates of 845 barrels of oil equivalent per day, comprised of 769 barrels of oil per day and 452 thousand cubic feet of natural gas per day. We operate the CE
#1-22-23H well with a 60% working interest and a 50% net revenue interest

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Table of Contents

Drilling Operations

Twin Buttes Federal Unit, Charging Eagle and Tall Bear Areas

Our
Tall Bear #16-15-16H well reached total measured depth of 19,800 feet in mid-October 2009 with a 9,442 foot horizontal
lateral in the Middle Bakken member. We continued to improve our drilling operation efficiencies, reaching total depth with liner installation in 25 days. We operate the
TB #16-15-16H well with a 60% working interest and a 50% net revenue interest. The well is located approximately five miles east of our wells on the Charging Eagle
prospect and is scheduled for a 19-stage fracture stimulation completion for later in the fourth quarter of 2009. The TB #16-15-16H well is the third and
final well that will be drilled during 2009 within the Twin Buttes Federal Unit.

Moccasin Creek

We
recently completed drilling pad construction in the Moccasin Creek area in the southwestern portion of our Fort Berthold leasehold. We spud our tenth well
on the FBIR, the MC #16-3-11H well, in October 2009. The well is intended to test the productive potential of the Bakken shale with an approximate 4,700 foot horizontal
lateral well bore design drilled on a 320-acre spacing unit. We operate the MC #16-3-11H well with a 60% working interest and a 49% net revenue interest.
This is the third well drilled under an exploration agreement reached during the fourth quarter 2008 pursuant to which we are required to pay 20% of the completed well costs for our 60% working
interest.

Upon
reaching total depth on the MC #16-3-11H well, we intend to skid the rig and spud the MC #16-3H well utilizing the same pad. We operate
the well with a 60% working interest and a 49% net revenue interest. The MC #16-3H well is also expected be drilled on a 320-acre spacing unit with an approximate 4,100
foot lateral.

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 ActivitiesLonger Laterals (8,000' to 10,000')Well

WI / NRI (%)

Days to TD*

Length of Lateral

Completion Date

Number of Stages

IP 24-Hour Test BOE/D

First 30 Day BOE Production

NoteTSB #16-8-7H


37.5 / 30.5


28


8.995'


6/7/2009


15


1,856


23,874

Flowing wellTSB #14-33-28H


50 /41


31


8,313'


8/3/2009


15


1,492


21,400

Flowing wellCE #1-22-10H


55 /45


32


9,949'


10/18/2009


15


1,288




Flowing wellTB #16-15-16H


60 /50


25


9,442'





19







Waiting completion


Shorter Laterals (4,000' to 7,000')Well

WI / NRI (%)

Days to TD*

Length of Lateral

Completion Date

Number of Stages

IP 24-Hour Test BOE/D

First 30 Day BOE Production

NoteMC #16-34-2H


60 /49


41


4,169'


4/23/2009


8


711


9,155

Flowing wellMC #16-34H


60 / 49


36


4,150'


5/4/2009


5


1,394


14,720

Flowing wellTSB #16-8-16H


50 /41


31


4,465'


6/18/2009


5


811


12,758

Flowing wellTSB #14-33-6H


50 /41


26


4,163'


8/24/2009


6


978


13,608

Flowing wellCE #1-22-23H


60 /50


19


6,620'


10/18/2009


13


845




Flowing wellMC #16-3-11H


60 /49





**4,700'













Spud October 2009MC #16-34H


60 /49





**4,100'













Spud after MC#16-3-11H


*Includes
running liner in the hole**Approximate
length of lateral


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Table of Contents




Production, Average Sales Prices, and Production Costs

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

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

For the three months ended

For the nine months endedSeptember 30, 2009

September 30, 2008

September 30, 2009

September 30, 2008Sales Volume:Gas (Mcf)


47,982


42,000


206,554


144,709Oil (Bbls)


61,121


14,832


112,921


43,691Production volumes (BOE)


69,118


21,832


147,347


67,809Price:Gas ($/Mcf)

$
2.70

$
3.57

$
2.62

$
7.45Oil ($/Bbls)

$
58.94

$
107.47

$
52.77

$
103.18Production costs ($/BOE):Lease operating expenses

$
3.80

$
31.06

$
3.44

$
36.16Production and property taxes

$
6.69

$
10.07

$
4.45

$
8.73Gathering, transportation & & marketing

$
0.21

$
0.96

$
0.46

$
1.15


Results of Operations

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

The Company reported a net loss for the three months ended September 30, 2009 of approximately $9,000 compared to a net loss of
$18.0 million for the same period in 2008. Included in the net loss for 2008 was an impairment charge of $15.5 million. There was no
impairment charge during the three months ended September 30, 2009. Additionally, the improvement in net loss is attributable to the new production from our FBIR wells, which began producing in
the second and third quarters of 2009, and from new wells coming on to production in the fourth quarter of 2008 in our Vermillion Basin area. For the period, our volumes on a BOE basis increased 217%
from 21,832 BOE in the third quarter of 2008 to 69,118 BOE during the third quarter of 2009. This increase in volumes was offset by lower oil and natural gas pricing during the three month period
ended September 30, 2009 versus the three month period ended September 30, 2008. Oil price realizations declined by 45% to $58.94 per barrel for the three month period ended
September 30, 2009, compared to $107.47 per barrel for the same period in 2008. Total natural gas price realizations decreased 24% to $2.70 per Mcf for the three month period ended
September 30, 2009, compared to $3.57 per Mcf for the same period in 2008. Our increased production for the period offset the lower pricing, resulting in an increase in oil and gas revenue of
$2.0 million or a 114% increase in revenue for the three month period ended September 30, 2009 compared to the same period in 2008.

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Table of Contents

For the three months endedSeptember 30,
2009

September 30,
2008Financial ResultsTotal revenue

$
3,739,329

$
1,782,351Total costs and expenses

$
3,748,369


19,742,000Net loss

$
(9,040
)
$
(17,959,649
)Diluted net loss per common share

$
(0.00
)
$
(0.20
)Capital Resources and LiquidityCash and cash equivalents at end of the period

$
1,754,518

$
11,191,928Net cash provided by (used in) operating activities

$
5,751,820

$
(4,803,130
)Capital expendituresoil and gas properties excluding accruals and proceeds from divestitures

$
9,370,292

$
2,758,879Adjusted EBITDA (see below discussion)

$
1,808,960

$
(461,635
)


Oil and Gas Revenue and Production

During the three month period ended September 30, 2009, as compared to the same period in 2008, crude oil production volumes
increased 312% due to new production from completion operations on our FBIR area during the second and third quarters of 2009. Natural gas production volumes increased 14% due to production from new
wells in our Vermillion Basin area which came on-line in the fourth quarter of 2008. Oil and natural gas revenues increased by $2.0 million or 114% in the third quarter of 2009
compared to the third quarter of 2008 primarily due to our increased volumes attributable to our recent well completions.

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of $740,185 during the three month period ended
September 30, 2009, as compared to $856,398 during the same period in 2008. The decrease is attributed to workover expenses recorded during 2008 and our curtailment of certain gas wells due to
low commodity prices in 2009, which reduced our lease operating expense for the wells shut in during the period.

Depletion, Depreciation and Amortization

Depreciation, depletion, amortization and abandonment liability accretion ("DD&A"), was $1.1 million for the three month period
ended September 30, 2009, compared to $1.2 million for the same period in 2008. DD&A expense decreased during the third quarter of 2009 compared to the same period in 2008. The decrease
in DD&A expenses was due to the impairment charges recognized in 2008, which reduced the full cost pool by $47.5 million year over year, thereby decreasing the DD&A expense recorded offset by
increases in total proved reserves and additions to the amortization base during the quarter.

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

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months
ended September 30, 2009, no impairment charges were recorded. For the three months ended September 30, 2008, we recorded an impairment of $15.5 million.

General and Administrative Expense

The Company's general and administrative costs were approximately $2.0 million for the three months ended September 30,
2009 compared to approximately $2.2 million for the same period in 2008. This 9% reduction for the period is primarily due to our ongoing cost containment efforts. Excluding the
non-cash stock-based compensation expense in each period, our general and administrative expenses declined by approximately $197,000 or 14% during the three month period ended
September 30, 2009 as compared to the same period in 2008. This decline is primarily attributed to lower costs related to employee costs, travel and consulting. Our stock- based compensation
expense of approximately $772,000 related to options and restricted stock issued to officers, directors and employees was recorded for the three months ended September 30, 2009. The expense was
equivalent to the approximate $775,000 stock-based compensation expense recorded for the same period in 2008.

EBITDA

In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gains or losses on
foreign currency, stock-based compensation expense and accretion of abandonment liability, ("Adjusted EBITDA") as a key indicator of financial operating performance and as a measure of the ability to
generate cash for operational activities, future capital expenditures and servicing of borrowings under the Company's Credit Facility. The Company's Adjusted EBITDA increased by approximately
$2.3 million to approximately $1.8 million for the three
months ended September 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 due to our
successful drilling and completion operations during the period as compared to the same period in 2008. Adjusted EBITDA is not a Generally Accepted Accounting Principle ("GAAP") measure of
performance. The Company uses this non-GAAP measure primarily to compare its performance with other companies in the industry that make a similar disclosure and as a measure of its current
liquidity. The Company believes that this measure may also be useful to investors for the same purpose and for an indication of the Company's ability to generate cash flow at a level that can sustain
or support our operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for operating income or loss, cash flow from operations determined
under GAAP or any other measure for determining the Company's operating performance that is calculated in accordance with GAAP. In addition, because Adjusted EBITDA is not a GAAP measure, it may not
necessarily be comparable to similarly titled measures employed by other companies. A reconciliation of Adjusted EBITDA and net income for the three months ended September 30, 2009 and 2008 is
provided in the table below:

Three months ended
September 30, 2009

Three months ended
September 30, 2008Reconciliation of Adjusted EBITDA:Net income (loss)

$
(9,040
)
$
(17,959,649
)Add back:Depreciation, depletion, amortization and accretion


1,050,481


1,220,222Asset impairment





15,500,000(Gain) / loss on foreign currency exchange


(4,384
)

2,992Stock based compensation expense


771,903


774,800Adjusted EBITDA

$
1,808,960

$
(461,635
)


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Results of Operations

For the Nine Months Ended September 30, 2009 compared to the Nine Months Ended September 30, 2008

The Company's net loss for the nine months ended September 30, 2009 of $2.2 million improved from a net loss of
$22.5 million for the same period in 2008. Included in the net loss for 2008 was an impairment charge of $15.5 million. There was no impairment charge during the nine months ended
September 30, 2009. For the nine month periods ended September 30, 2008 and 2009, our volumes on a BOE basis increased by 117% from 67,809 BOE to 147,347 BOE. The increase in volumes is
attributable to new production from our FBIR wells, which began production in the second and third quarters 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 nine month period in 2009 that were shut-in for workover activities during the same period of 2008. This increase
in volumes was offset by lower oil and natural gas pricing realized during the nine month period ended September 30, 2009 versus the nine month period ended September 30, 2008. Oil price
realizations declined by 49% to $52.77 per barrel for the nine month period ended September 30, 2009, compared to $103.18 per barrel for the same period in 2008. Total natural gas price
realizations decreased 65% to $2.62 per Mcf for the nine month period ended September 30, 2009, compared to $7.45 per Mcf for the same period in 2008. Due to our increase in production, our
total revenue increased by approximately $0.8 million during the nine month period ended 2009 compared to the same period in 2008.

For the nine months endedSeptember 30,
2009

September 30,
2008Financial ResultsTotal revenue

$
6,543,719

$
5,744,578Total costs and expenses


8,718,520


28,234,704Net loss

$
(2,174,801
)
$
(22,490,126
)Diluted net loss per common share

$
(0.02
)
$
(0.25
)Capital Resources and LiquidityCash and cash equivalents at end of the period

$
1,754,518

$
11,191,928Net cash provided by (used in) operating activities

$
5,058,188

$
(3,113,204
)Capital expendituresoil and gas properties excluding accruals and proceeds from divestitures

$
18,778,013

$
11,930,131Adjusted EBITDA (see below discussion)

$
1,899,931

$
(1,124,015
)


Oil and Gas Revenue and Production

During the nine month period ended September 30, 2009 as compared to the same period in 2008, natural gas production volumes
increased 43% 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 158% due to new production coming on-line during May and June of 2009 from completion operations in our FBIR area. Due to the increase in
both oil and natural gas volumes, total revenues increased by $0.8 million to $6.5 million for the nine month period ended September 30, 2009, compared to the same period in 2008.

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of $1.2 million during the nine month period ended
September 30, 2009, as compared to $3.1 million during the same period in 2008. In the first nine months of 2008, we performed workover operations on our producing Bakken oil wells in
McKenzie County, North Dakota. The net cost of approximately $1.7 million

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related
to the repair work was charged to oil and gas production costs and expenses in the first nine months of 2008. Excluding workover operations but including both lease operating and production
tax expense, our lease operating costs decreased by approximately $172,000 for the nine month period ended September 30, 2009, as compared to the same period in 2008. We have shut in certain
oil and gas wells due to low commodity prices that rendered the wells currently non-commercial, which reduced our lease operating expense during the period.

Depletion, Depreciation and Amortization

DD&A was $1.9 million for the nine month period ended September 30, 2009, compared to $3.1 million for the same
period in 2008. DD&A expense decreased during the first nine months 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 offset by increases in total proved reserves and additions to the amortization base during the year.

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 nine months ended September 30, 2009
no impairment charge was recorded. For the nine months ended September 30, 2008 an impairment charge of $15.5 million was recorded.

General and Administrative Expense

The Company's general and administrative costs were approximately $5.6 million for the nine months ended September 30,
2009 compared to approximately $6.5 million for the same period in 2008. This 14% reduction for the period is primarily due to lower stock-based compensation expense recorded in 2009 versus
2008 and an ongoing effort to reduce general and administrative costs company-wide. Excluding the non-cash stock-based compensation expense in each period, our general and
administrative expenses declined by approximately $335,000, or 9%, during the nine month period of 2009 as compared to the same period in 2008. This decline is primarily attributed to lower costs
related to employee costs, travel and consulting. In addition, we recorded lower stock-based compensation expense of approximately $2.1 million for the nine months ended September 30,
2009 compared to $2.7 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 in part to the reversal recorded 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, gain on foreign
currency, stock-based compensation expense and accretion of abandonment liability ("Adjusted EBITDA") as a key indicator of financial operating performance and as a measure of the ability to generate
cash for operational activities, future capital expenditures and servicing of borrowings under the Company's Credit Facility. The Company's Adjusted EBITDA increased by approximately
$3.0 million to approximately $1.9 million for the nine months ended September 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")

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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 nine months ended September 30, 2009
and 2008 is provided in the table below:

Nine months ended
September 30,
2009

Nine months ended
September 30,
2008Reconciliation of Adjusted EBITDA:Net income (loss)

$
(2,174,801
)
$
(22,490,126
)Add back:Depreciation, depletion, amortization and accretion


1,938,275


3,104,298Asset impairment





15,500,000(Gain) / loss on foreign currency exchange


(10,526
)

19,501Stock based compensation expense


2,146,983


2,742,312Adjusted EBITDA

$
1,899,931

$
(1,124,015
)


Liquidity and Capital Resources

The following table sets forth our liquidity and capital resources as of the three and nine months ended September, 2009 and 2008 and
does not include liquidity generated by the registered offering completed in October 2009:

For the three months ended
September 30,

For the nine months ended
September 30,2009

2008

2009

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

$
1,754,518

$
11,191,928

$
1,754,518

$
11,191,928Net cash provided by (used in) operating activities


5,751,820


2,056,788


5,058,188


(3,113,204
)Net cash used in investing activities


(8,044,659
)

(9,637,025
)

(18,202,560
)

(16,361,674
)Net cash provided by financing activities


225,450


17,572,738


7,317,625


17,651,488Net cash flow


(2,067,389
)

9,992,501


(5,826,747
)

(1,823,390
)


Kodiak
ended the third quarter of 2009 with total working capital of approximately $6.1 million, which included cash and cash equivalents of approximately $1.8 million as
compared to working capital at year-end 2008 of approximately $15.4 million, which included cash and cash equivalents of approximately $7.6 million. Following the end of our
third quarter, in October 2009, we completed a public offering of 13.8 million shares of our common stock, resulting in net proceeds of approximately $28.6 million (gross proceeds of
approximately $30.3 million). In May 2009, we completed a registered direct offering of 9.6 million shares of our common stock, resulting in net proceeds of $7.1 million (gross
proceeds of $7.2 million).

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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 September 30, 2009, we had prepaid $7.3 million towards the cost of tubular goods ($6.8 million of
tubular goods are inventoried in third party yards and $0.5 million of deposits for tubular goods 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 $2.4 million from December 31, 2008 to September 30, 2009, approximately $6.9 million of prepaid tubular
goods were used in operations ($3.4 million of which has been billed to working interest partners), and we took delivery of an additional $6.0 million of tubular goods of which we had
made previous deposits of $1.5 million, therefore reducing our deposit balance to $0.5 million.

Net
cash flow provided by operating activities for the nine months ended September 30, 2009 was $5.1 million. Net cash used as investing activities (which includes
recoupments from partners and restricted cash changes) totaled $18.2 million for the nine months ended September 30, 2009. These investing items were comprised of $18.8 million
for oil and gas capital investments on an accrued accounting basis and then adjusted for oil and gas properties sold, prepaid tubular goods, expense accruals, and asset retirement obligations,
resulting in a cash basis oil and gas capital investment of $18.8 million for the nine months ended September 30, 2009.

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 nine months ended September 30, 2009, our oil and natural gas revenue increase by 16% from
$5.6 million as of September 30, 2008 to $6.5 million as of September 30, 2009. This increase is largely the result of the increase in our crude oil production in 2009
compared to 2008. Total costs and expenses decreased to $8.7 million for the nine months ended September 30, 2009 from $28.2 million for same period of 2008. This decline is
largely due to an impairment charge of $15.5 million recognized in 2008 versus no impairment charge in 2009, workover expenses of $1.7 million incurred in 2008 that did not occur in
2009, a decrease in general and administrative expenses (including a decrease in the non-cash charge for stock based compensation due to a reversal of non-vested performance
based options during the second quarter of 2009 of approximately $122,000) and lower stock-based compensation expense caused by a lower exercise price at which options were issued in 2009 as compared
to the same period in 2008.

As
discussed above in note 7 to the financial statements, we have a Credit Facility currently available to us through Bank of the West. Any 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 located outside the boundaries of the FBIR. The Credit Facility also
provides for letters of credit that may be used for general corporate purposes. Effective November 1, 2009, the borrowing base under the Credit Facility is $1.6 million. The borrowing
base is re-determined semi-annually in May and November. To date, we have never borrowed against our Credit Facility, and since September 30, 2009, we have not had any
new letters of credit issued. See note 7 to the financial statements for further information on our existing Credit Facility.

During
the first nine months of 2009, we incurred capital expenditures of approximately $18.8 million. We continue to evaluate and monitor our capital expenditures in relation to
commodity prices. As oil prices have improved since the beginning of the year and drilling costs have declined during this same period, we have continued to drill and complete wells in the Williston
Basin. We currently anticipate that we will continue those operations and our capital expenditures for the year are

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expected
to be approximately $21.0 million for the 2009 fiscal year. Such estimate does not include any potential costs or fees associated with the Second Rig.

The
following tables set forth our capital expenditures for the nine months ended September 30, 2009 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 Nine Months Ended September 30,
2009 ($000)

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





700Bakken wells and related infrastructure


18,400


19,555Acreage/Seismic


(142
)

500Total Williston Basin

$
18,258

$
20,755WyomingVermillion Basin wells and related infrastructure

$
517

$
150Acreage/Seismic


60


Total Wyoming

$
577

$
150Total All Areas

$
18,835

$
20,905


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


Oil and Gas Properties

As of September 30, 2009, we had several hundred lease agreements representing approximately 163,000 gross and 87,000 net acres,
primarily in the Green River and Williston Basins.

As
of September 30, 2009, we had an interest in approximately 55,000 gross acres and 35,000 net acres in the Bakken oil play located on the FBIR in Mountrail and Dunn Counties,
North Dakota. The majority of our lands in this area are administered by the Bureau of Indian Affairs on behalf of the individual members of the Three Affiliated Tribes of the FBIR. Typically, these
lands are acquired through a private negotiation with the individual land owners or the Three Affiliated Tribes and have a primary lease term of five years. The land owner typically retains an 18%
landowner royalty. In most cases, these lands require an annual delay rental of $2.50 per net acre.

As
of September 30, 2009, we owned an interest in approximately 44,000 gross and 25,000 net acres in the Williston Basin outside the FBIR in Sheridan County, Montana and McKenzie
and Divide Counties, North Dakota. This acreage is prospective for Mission Canyon, Red River, Bakken and Three Forks formations. We intend to drill two wells to test the Red River formation in late
2009 or early 2010, which will provide us with an opportunity to evaluate the Bakken and Three Fork formations.

Our
leasehold interests in the Vermillion Basin total approximately 44,000 gross and 9,200 net acres as of September 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 a proportional share of

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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 September 30,
2009.

Undeveloped
Acreage(1)

Developed
Acreage(2)

Total
AcreageGross

Net

Gross

Net

Gross

NetGreen River BasinWyoming(3)


42,554


9,770


1,520


908


44,074


10,678Colorado


7,339


4,960


0


0


7,339


4,960Williston BasinMontana


28,453


17,413


800


400


29,253


17,813North Dakota


63,831


39,403


5,600


3,064


69,431


42,467Other BasinsWyoming


12,562


10,875


0


0


12,562


10,875Acreage Totals


154,739


82,421


7,920


4,372


162,659


86,793


(1)Undeveloped
acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage includes proved reserves.(2)Developed
acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production.(3)Excludes
10,261 gross (6,127 net) acres that can be earned pursuant to existing farm-in agreements.


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

The
following table sets forth the gross and net acres of undeveloped land subject to leases that will expire either in 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


1,000


800December 31, 2010


31,101


16,607December 31, 2011


7,791


3,773December 31, 2012


32,403


19,342Total


72,295


40,522


Off Balance Sheet Arrangements

As discussed above in note 2 to the financial statements, on September 14, 2009, the Company entered into an Amendment in
respect of its Second Rig. Under the terms of the Original Second Rig Contract, which has a two-year drilling commitment, the Company was scheduled to take delivery of the Second Rig in
February 2009. In consideration of such deferral, pursuant to the Amendment, the Company has agreed to make Delay Payments until the earlier of delivery of the Second Rig or the expiration of
12 months. If the Company does not accept delivery of the Second Rig, the aggregate

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amount
of the Delay Payments will be $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 Original Second Rig Contract. 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.

Other
than standard operating leases and our drilling rig commitments, as amended, the Company did not have any other off balance sheet financing arrangements at September 30,
2009 and December 31, 2008.

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.            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
June 2009, the Financial Accounting Standards Board ("FASB") issuedThe FASB Accounting Standards Codification("ASC') which became
effective for interim and annual reporting periods ending after September 15, 2009. The Codification is the source of authoritative U.S. GAAP recognized by the FASB. The adoption of the
Codification did not have a material impact on the Company's financial position or results of operations.

In
December 2007, the FASB issued a pronouncement regarding business combinations ("ASC 805"). This pronouncement is effective for the Company's financial statements issued after
January 1, 2009. Under previous pronouncements, organizations utilized the announcement date as the measurement date for the purchase price of the acquired entity. ASC 805 requires measurement
at the date the acquirer obtains control of the acquiree, generally referred to as the acquisition date. ASC 805 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 ASC 805, 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 ASC 805 are applied
prospectively, the impact to the Company cannot be determined until the transactions occur.

In
May 2009, the FASB issued a pronouncement regarding subsequent events ("ASC 855"). ASC 855 provides guidance for management's assessment of subsequent events. An additional disclosure

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required
by ASC 855 is to identify the 'as of' date of the subsequent event. ASC 855 is effective for interim and annual reporting periods ending after June 15, 2009. The adoption of ASC 855
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 $206,554 change in our gross gas production revenue. A $1.00 per
barrel change in the market price of oil will result in an approximate $112,921 change in our gross oil production revenue.

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
$31,443 annual impact if all of our cash, as of September 30, 2009, was invested in interest bearing notes.

ITEM 4.    CONTROLS AND PROCEDURES

Evaluation of Disclosure 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 September 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.

Changes in Internal Control Over Financial Reporting

There have not been any changes in the Company's internal control over financial reporting (as defined in
Rules 13a-15(f) and 15d-15(f) promulgated by the SEC under the Exchange Act) during the Company's most recently completed fiscal quarter that have materially affected,
or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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PART IIOTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

None.

ITEM 1A.    RISK FACTORS

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 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.

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

The Company held its Annual General Meeting of Shareholders on August 13, 2009. The meeting was held to elect five directors to
serve until the 2010 Annual General Meeting of Shareholders and to ratify the selection of Hein & Associates LLP as independent auditors of the Company for the year ending
December 31, 2009.

The
results of the voting related to the elections of the nominees for director are below. The "For" column represents the number of affirmative votes, and the "Withheld" column
represents the number of abstentions and broker non-votes by holders of common stock represented by either proxy or in person at the meeting.

Name

For

WithheldLynn A. Peterson


84,607,525


2,603,063James E. Catlin


84,023,977


3,186,611Rodney D. Knutson


84,599,230


2,611,358Herrick K. Lidstone, Jr.


84,132,396


3,078,192Don A. McDonald


84,657,496


2,553,092


Shareholders
voted 85,582,666 shares for the proposal to ratify the selection of Hein & Associates LLP as independent auditors of the Company for the fiscal year ending
December 31, 2009, with 1,627,923 shares withheld.

ITEM 5.    OTHER INFORMATION

None.

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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.November 5, 2009

/s/ LYNN A. PETERSON Lynn A. Peterson President and Chief Executive OfficerNovember 5, 2009

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


34

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