Kodiak Oil & Gas (KOG) 10-Q 2008 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, 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, 2008

Commission File No. 001-32920

(Exact name of registrant as specified in its charter)

Yukon Territory	N/A
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1625 Broadway, Suite 250
Denver, Colorado 80202
(Address of principal executive offices, including zip code)

303-592-8075
(Registrant's telephone number, including area code)

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesý Noo

        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 definition of "accelerated filer", large accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filero Accelerated filerý Non-accelerated filero
(Do not check if a smaller reporting company) Smaller reporting companyo

        Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noý

        95,129,431 shares, no par value, of the Registrant's Common Stock were issued and outstanding as of October 31, 2008.

KODIAK OIL & GAS CORP.

INDEX

PART 1—FINANCIAL INFORMATION		2
ITEM 1.	FINANCIAL STATEMENTS	2
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	31
ITEM 4.	CONTROLS AND PROCEDURES	31
PART II—OTHER INFORMATION		32
ITEM 1.	LEGAL PROCEEDINGS	32
ITEM 1A.	RISK FACTORS	32
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	34
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	34
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	34
ITEM 5.	OTHER INFORMATION	34
ITEM 6.	EXHIBITS	34
SIGNATURES		35

1

PART 1—FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

				(UNAUDITED) September 30, 2008			(AUDITED) December 31, 2007
ASSETS
Current Assets:
	Cash and cash equivalents			$	11,191,928		$	13,015,318
	Accounts receivable
		Trade			2,110,594			1,373,843
		Accrued sales revenues			762,080			789,652
	Prepaid expenses and other				7,052,389			198,996
			Total Current Assets		21,116,991			15,377,809
Oil and gas properties (full cost method), at cost:
	Proved oil and gas properties				80,266,344			77,272,437
	Unproved oil and gas properties				27,220,726			21,904,737
	Wells in progress				33,905			414,074
	Less-accumulated depletion, depreciation, amortization, accretion and asset impairment				(59,779,671	)		(41,204,821	)
	Net oil and gas properties				47,741,304			58,386,427
Other property and equipment, net of accumulated depreciation of $243,009 in 2008 of $176,458 in 2007					265,312			312,017
Restricted investments					244,740			255,068
Total Assets				$	69,368,347		$	74,331,321
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
	Accounts payable and accrued liabilities			$	2,399,055		$	5,163,457
Noncurrent Liabilities:
	Asset retirement obligation				772,252			874,498
			Total Liabilities		3,171,307			6,037,955
Commitments and Contingencies—Note 6
Stockholders' Equity:
	Common stock—no par value; unlimited authorized
	Issued and outstanding: 95,129,431 shares in 2008 and 87,992,926 shares in 2007
	Contributed surplus				135,488,723			115,094,923
	Accumulated deficit				(69,291,683	)		(46,801,557	)
			Total Stockholders' Equity		66,197,040			68,293,366
Total Liabilities and Stockholders' Equity				$	69,368,347		$	74,331,321

SEE ACCOMPANYING NOTES

2

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

			Three months ended September 30,						Nine months ended September 30,
			2008			2007			2008			2007
Revenues:
	Gas production		$	149,804		$	226,116		$	1,077,887		$	750,591
	Oil production			1,594,080			1,974,133			4,507,974			4,896,077
	Interest			38,467			305,749			158,717			1,323,987
		Total revenue		1,782,351			2,505,998			5,744,578			6,970,655
Cost and expenses:
	Oil and gas production			856,398			460,867			3,121,967			1,197,639
	Depletion, depreciation, amortization and accretion			1,220,222			2,036,384			3,104,298			4,062,397
	Asset impairment			15,500,000			20,000,000			15,500,000			34,000,000
	General and administrative			2,162,388			2,091,145			6,488,938			5,380,549
	(Gain)/loss on currency exchange			2,992			(97,523	)		19,501			(780,976	)
		Total costs and expenses		19,742,000			24,490,873			28,234,704			43,859,609
Net loss			$	(17,959,649	)	$	(21,984,875	)	$	(22,490,126	)	$	(36,888,954	)
Basic & diluted weighted-average common shares outstanding				91,742,529			87,799,774			89,265,263			87,658,770
Basic & diluted net loss per common share			$	(0.20	)	$	(0.25	)	$	(0.25	)	$	(0.42	)

SEE ACCOMPANYING NOTES

3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

			Nine Months Ended September 30,
			2008			2007
Cash flows from operating activities:
	Net loss		$	(22,490,126	)	$	(36,888,954	)
Reconciliation of net loss to net cash (used in) provided by operating activities:
		Depletion, depreciation, amortization and accretion		3,104,298			4,062,397
		Asset impairment		15,500,000			34,000,000
		Stock based compensation		2,742,312			1,689,377
Changes in currrent assets and liabilites:
		Accounts receivable—trade		(736,751	)		(27,555	)
		Accounts receivable—accrued sales revenue		27,572			(89,616	)
		Prepaid expenses and other		6,524			(59,636	)
		Accounts payable and accrued liabilities		(1,267,033	)		(2,069,346	)
Net cash (used in)/provided by operating activities				(3,113,204	)		616,667
Cash flows from investing activities:
		Oil and gas properties		(11,930,131	)		(39,855,687	)
		Sale of oil and gas properties		2,437,892			—
		Equipment		(19,846	)		(218,820	)
		Restricted investments		10,329			(28,887	)
Net cash (used in) investing activities				(9,501,756	)		(40,103,394	)
Cash flows from financing activity:
		Proceeds from the issuance of shares		18,935,000			382,150
		Issuance costs		(1,283,512	)		—
		Prepaid tubular goods		(6,859,918	)		—
Net cash provided by financing activities				10,791,570			382,150
Net change in cash and cash equivalents				(1,823,390	)		(39,104,577	)
Cash and cash equivalents at beginning of the period				13,015,318			58,469,263
Cash and cash equivalents at end of the period			$	11,191,928		$	19,364,686
Supplemental cash flow information
	Oil & gas property accrual included in Accounts payable and accrued liabilities		$	47,500		$	375,100
	Asset retirement obligation		$	(65,143	)	$	100,379

SEE ACCOMPANYING NOTES

4

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 Alternext US and its 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 on September 28, 2001.

Note 2—Basis of Presentation and Significant Accounting Policies

Basis of Presentation

        The condensed 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 Corporation's business is transacted in US dollars and, accordingly, the financial statements are expressed in US dollars.

        These unaudited interim financial statements have been prepared in accordance with U.S. generally accepted accounting principles ("GAAP") for interim financial information and reflect our condensed consolidated financial position as of December 31, 2007 and September 30, 2008. These statements also show our condensed consolidated statement of operations for the three and nine months ended September 30, 2007 and 2008 and our condensed consolidated statement of cash flows for the nine months ended September 30, 2007 and 2008. These statements include all normal recurring adjustments that we believe are necessary to fairly state our financial position, operating results and cash flows. Because all of the disclosures required by U.S. generally accepted accounting principles for annual consolidated financial statements are not included herein, condensed consolidated financial statements should be read in conjunction with the Company's audited consolidated financial statements included in the Annual Report on Form 10-K for the fiscal year ended December 31, 2007. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. Certain amounts have been reclassified to conform to the current period consolidated financial statement presentation; such reclassifications had no effect on the period presented.

Use of Estimates in the Preparation of Financial Statements

        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

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

        As of September 30, 2008, the Company had approximately $11.0 million in a money market account with its bank. The money market account is limited to six withdrawals per month; however, there are no other redemption restrictions. Therefore, the Company classified the entire balance as Cash and Cash Equivalents at September 30, 2008.

Prepaid Expenses and Other

        Included in prepaid expenses and other are deposits made on orders of tubular goods required for the Company's drilling program. As of September 30, 2008 there was approximately $6.9 million of deposits made and recorded. As of December 31, 2007, there were no deposits made or recorded.

Restricted Investment

        The restricted investment balance as of September 30, 2008, is comprised of: (a) $191,886 certificate of deposit to collateralize a surety bond to provide for state bonding requirements for plugging and abandonment liabilities; and (b) $52,348 certificate of deposit to collateralize the costs of office improvements that will be released over the four year remaining term of the lease at $17,450 per year.

Concentration of Credit Risk

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

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

Oil and Gas Producing Activities

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

6

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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 2008 and 2007 approximately $0 and $1.1 million respectively, of unproved land costs was reclassified to proved property and was included in the ceiling test and depletion calculations.

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

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

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

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

        In 2007, primarily as the result of the Company's inability to establish production and qualified reserves in its deep Vermillion Basin project, low natural gas prices in Wyoming, and the impairment of certain undeveloped properties in Wyoming and North Dakota, the Company recorded an impairment expense of $34.0 million.

7

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

        As of September 30, 2008, oil and natural gas prices decreased significantly from the record highs seen during the summer of 2008. Specifically, natural gas prices in the Rocky Mountains decreased significantly due to the reduction in take-away capacity caused by pipeline maintenance and repairs during September 2008. As of September 30, 2008, based on realized oil and gas prices of $87.81 per barrel and $4.69 per Mcf, the Company removed four wells with approximately 348,000 BOE from its proved undeveloped (PUD) category of its reserve base. The removal of these proved undeveloped wells from the reserve base was due to one well that became uneconomic based on September 30, 2008 pricing and anticipated capital requirements related to the well and three wells that the Company removed from its drilling plans. The full cost pool exceeded the ceiling by approximately $15.5 million after taking into account the decreases in the reserve base due to the above factors and the decreases in prices at the quarter end. Subsequent to September 30, 2008, there was no recovery in price, therefore, an impairment expense of $15.5 million was recorded during the quarter ended September 30, 2008.

Wells in Progress

        Wells in progress at December 31, 2007 and September 30, 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 is then transferred to proved property when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods.

Impairment of Long-lived Assets

        The Company's unproved properties are evaluated quarterly for the possibility of potential impairment. In the nine months ended September 30, 2007 the Company reclassified approximately $1.1 million of unproved property costs to the full cost pool. The Company recorded an impairment expense of $34.0 million in 2007. In the nine months ended September 30, 2008, the Company recorded an impairment expense of $15.5 million.

Deferred Financing Costs

        Deferred financing costs include debt issuance costs incurred in connection with the Company's credit facility, which are being amortized over the two year term of the credit facility (see Note 7). The Company did not record amortization expense at September 30, 2008 as the Company did not enter into the credit facility until September 11, 2008.

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.

8

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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, 2008, and December 31, 2007 were not significant.

Asset Retirement Obligation

        The Company follows SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the condensed consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are also included in the ceiling test calculation. The asset retirement liability is allocated to operating expense using a systematic and rational method. As of September 30, 2008, and December 31, 2007, the Company has recorded a net asset of $537,546 and $660,986 and a related liability of $772,252 and $874,498, respectively. In December 2007, the Company revised its estimated dismantlement and abandonment costs based upon the actual costs of recently plugged and abandoned wells. The information below reconciles the value of the asset retirement obligation for the periods presented.

		For the Period Ended
		September 30, 2008			December 31, 2007
Balance beginning of period		$	874,498		$	249,695
	Liabilities incurred		—			60,289
	Liabilities settled		(147,252	)		(3,021	)
	Revisions in estimated cash flows		—			482,544
	Accretion expense		45,006			84,991
Balance end of period		$	772,252		$	874,498

9

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Off Balance Sheet Arrangements

        Other than standard operating leases, the Company did not have any off-balance sheet financing arrangements at September 30, 2008 and December 31, 2007.

Recently Adopted Accounting Pronouncements

        In September 2006, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 157, "Fair Value Measurements." The statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. In February 2008, the FASB issued Staff Position No. FAS 157-2 which proposed a one year deferral for the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually).

        On January 1, 2008 we elected to implement this statement with the one-year deferral. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations or cash flows. Beginning January 1, 2009, we will adopt the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis. We are in the process of evaluating this standard with respect to our effect on non- financial assets and liabilities and have not yet determined the impact that it will have on our financial statements upon full adoption in 2009.

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

Recently Issued Accounting Pronouncements

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

    ��   In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51" ("FAS 160"). This statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the

10

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

deconsolidation of a subsidiary. FAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. The Company does not expect that the adoption of FAS 160 will have a material effect on its financial position or results of operations.

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

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

        In June 2008, the FASB issued FSP No. EITF 03-6-1, "Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities," (FSP EITF 03-6-1). FSP EITF 03-6-1 states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share pursuant to the two-class method. FSP EITF 03-6-1 becomes effective for the Company on January 1, 2009. Management has determined that the adoption of FSP EITF 03-6-1 will not have an impact on the Financial Statements.

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, 2008, and the year ended December 31, 2007, and does not include amounts that were capitalized and reclassified to producing wells in the same period.

		For the Nine Months Ended September 30, 2008			For the Year Ended December 31, 2007
Beginning balance		$	414,074		$	7,700,415
Additions to capital wells in progress costs pending
	the determination of proved reserves		33,905			414,074
Reclassifications to wells, facilities, and equipment
	based on the determination of proved reserves to
	full cost pool		(414,074	)		(7,700,415	)
Ending balance		$	33,905		$	414,074

11

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4—Common Stock

        On July 14, 2008, the Company filed a Registration Statement on Form S-3 with the United States Securities and Exchange Commission. Under this registration statement, which was declared effective on July 24, 2008, we may from time to time offer and sell common stock and debt securities that may be fully and unconditionally guaranteed by all of our subsidiaries for up to $150 million.

        In August 2008, the Company issued 6,820,000 common shares in a public offering for gross proceeds of $18,755,000. The Company paid $1,283,512 in commissions and expenses. The net proceeds will be used primarily for drilling and completion activities on the Company's leases in the Bakken oil play located on the Fort Berthold Indian Reservation 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 1,606,000 stock options at $2.65 per share and 1,930,000 stock options during the nine month period ended September 30, 2008 and 2007, respectively.

        Compensation expense charged against income for all stock-based awards during the nine months ended September 30, 2008 and September 30, 2007, was approximately $2.7 million and $1.7 million, pre-tax respectively which is included in general and administrative expense in the Condensed Consolidated Statements of Operations.

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

	For the Periods Ended
	September 30, 2008			December 31, 2007
Risk free rates		4.35 - 4.53	%		4.46 - 5.89	%
Dividend yield		0	%		0	%
Expected volatility		54.37 - 66.65	%		53.45 - 56.26	%
Weighted average expected stock option life		3.64 years			5.86 years
The weighted average fair value at the date of grant for stock options granted is as follows:
Weighted average fair value per share	$	1.55		$	3.33
Total options granted		6,930,500			2,044,000
Total weighted average fair value of options granted	$	10,774,400		$	6,800,579

12

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5—Stock-based Compensation Plan (Continued)

        A summary of the stock options outstanding as of September 30, 2008, is as follows:

		Number of Options			Weighted Average Exercise Price
Balance outstanding at December 31, 2007			6,112,000		$	3.24
	Granted		1,606,000			2.65
	Canceled		(475,000	)		4.53
	Exercised		(312,500	)		0.58
Balance outstanding at September 30, 2008			6,930,500		$	3.03
Options exercisable at September 30, 2008			4,481,331		$	2.73

        At September 30, 2008, stock options outstanding were as follows:

Exercise Price	Number of Shares		Weighted Average Remaining Contractual Life (Years)
$0.45-$1.00		1,025,500		0.53
$1.01-$2.00		875,000		2.04
$2.01-$3.00		965,000		6.02
$3.01-$4.00		2,330,000		4.65
$4.01-$5.00		270,000		2.74
$5.01-$6.26		1,465,000		8.65
		6,930,500		4.67

        The aggregate intrinsic value of both outstanding and vested options as of September 30, 2008, was $1,331,550 based on the Company's September 30, 2008, closing common stock price of $1.50. The total grant date fair value of the shares vested during the nine months ended September 30, 2008 was $2,052,493. As of September 30, 2008, there was $4,123,490 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, 2008, there were 48,000 unvested shares of restricted stock grants with a weighted-average grant date fair value of $4.21 per share. Total unrecognized compensation cost of $166,456 related to non-vested restricted stock is expected to be recognized over a three-year period. The Company recognizes compensation cost over the requisite service period for the entire award. The fair value of restricted stock grants is based on the stock price on the grant date and the Company assumes no annual forfeiture rate.

Note 6—Commitments and Contingencies

        The Company leases office facilities under an operating lease agreement that expires on September 30, 2012. Rent expense was $207,105 and $102,314 for the nine month periods ended September 30, 2008 and 2007, respectively.

13

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6—Commitments and Contingencies (Continued)

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

2008	$	64,876
2009		265,408
2010		276,827
2011		289,737
2012		147,321
Total	$	1,044,169

        During the second quarter of 2008, the Company entered into two-year contracts for the use of two new-build drilling rigs, with the first rig now scheduled for delivery in November 2008 and the second one scheduled to follow in the first quarter of 2009. Each of the contracts provide for stand-by drilling rates of $18,000 per day. It is contemplated that these rigs will be mobilized to our acreage holdings on the Fort Berthold Indian Reservation, or FBIR. The drilling contracts for the two new-build rigs contain a provision allowing us to terminate the contract prior to delivery of the rigs or at any time during the two-year period in exchange for a payment equal to the stand-by drilling rate per day multiplied by 120 days, or $2,160,000 per contract.

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

Note 7—Credit Agreement

        On September 11, 2008, our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., entered into a $20 million, two-year, revolving, senior secured credit facility (the "Credit Facility") with Bank of the West, NA. Borrowings made under the Credit Facility are guaranteed by the Company and secured by mortgages on substantially all of our producing oil and gas properties. The Credit Facility also provides for letters of credit that may be used for general corporate purposes. Our aggregate borrowings and outstanding letters of credit under the Credit Facility may not, at any time, exceed the borrowing base. Interest on borrowings under the Credit Agreement accrues at variable interest rates, at our election, at either:

(i)

the prime rate plus a margin of 0.0% to 0.25% based on borrowing base utilization; or



(ii)

LIBOR plus a margin of 1.50% to 2.00% based on borrowing base utilization.

        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 Agreement divided by current liabilities excluding any mark-to-market assets or liabilities that may occur due to Kodiak's hedging activities), determined at the end of each quarter, of not less than 1:1; and (2) a interest coverage ratio of trailing twelve month adjusted EBITDA to interest of not less than 3:1; and (3) a total funded debt to tangible net worth ratio on not more than 2:1. 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

14

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7—Credit Agreement (Continued)

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

        As of September 30, 2008 there were no loans or letter of credit outstanding under the Credit Facility. As of October 31, 2008, we had no outstanding borrowings under the Credit Agreement and had no commercial letters of credit outstanding or standby letters of credit outstanding. The available borrowing base under the Credit Facility was $5.0 million. We will capitalize approximately $37,000 in deferred financing costs related to the institution of the Credit Facility, which will be amortized on a straight line basis over the term of the Credit Facility.

        Kodiak Oil & Gas (USA) Inc. ("Kodiak USA") entered into an ISDA Master Agreement (the "ISDA Agreement") dated September 30, 2008, with Bank of the West, under which the Company may enter into hedging transactions designed to protect against changes in interest rates, currency exchange rates, and fluctuations in the price of oil, gas, hydrocarbons or other commodities. Kodiak USA's obligations under the ISDA Agreement are secured by a Mortgage, Security Agreement, Assignment, Financing Statement and Fixture Filing dated as of September 11, 2008. The Company's obligations under the ISDA Agreement is cross-defaulted with Kodiak USA's revolving credit facility with Bank of the West.

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

        Effective November 3, 2008, the Company entered into a letter agreement with a private, third-party oil and gas company to drill up to seven wells on certain of Kodiak's lands. The first two wells, the MC #16-34-2H and the MC #16-34H, are anticipated to be drilled under a participation agreement that will be executed prior to the spud date of the first well. Under this participation agreement, Kodiak will pay 20% of the drilling and completion costs associated with the first, third, fifth and seventh wells for its 60% WI and the joint venture partner will pay 80% of the wells' costs for its 40% interest. All other wells on the lands covered under the participation agreement will be drilled in proportion to the 60/40 percent working interest of each party. The first seven wells must be drilled within 30 months of the date of the participation agreement. By drilling the wells on a promoted basis, the third party will earn 40% under certain lands where Kodiak owns 100% working interest. Under the letter agreement, the total promote on the wells to be drilled will not exceed $8.5 million to the third party.

15

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

Forward-Looking Statements

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

        Forward-looking statements are based on assumptions and estimates and are subject to risks and uncertainties. We have identified in this Quarterly Report some of the factors that may cause actual results to differ materially from those expressed or assumed in any of our forward-looking statements. There may be other factors not so identified. Factors that may cause actual results to differ materially from those expressed or implied by our forward-looking statements include, but are not limited to, the factors set forth, from time to time, by us in reports filed with the SEC, including those described under the heading "Risk Factors" in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2007 and the following:

•

our future financial and operating performance;

•

our business strategy;

•

the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and producing oil and natural gas;

•

market demand;

•

drilling of wells;

•

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

•

the uncertainty of reserves estimates and reserves life;

•

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

•

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

•

our dependence on key personnel;

•

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

•

health, safety and environmental risks;

•

uncertainties as to the availability and cost of financing;

•

unforeseen liabilities arising from litigation; and

•

the possibility that government policies or laws may change or governmental approvals may be delayed or withheld.

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

16

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

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

Overview

        Kodiak Oil & Gas Corp. 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 Green River Basin of Wyoming and Colorado and the Williston Basin of North Dakota and Montana. 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 conventional and unconventional prospects, that we have the opportunity to explore, drill and develop.

        In 2008, our efforts in the Eastern Bakken oil play in Mountrail and Dunn Counties North Dakota have been focused on lease acquisition and development of an inventory of drilling permits, due primarily to the unavailability of drilling rigs. Now that we have taken delivery of our first new built rig as discussed below, we are focused on applying our capital to the drilling and completion of wells in this play. Accordingly, as we move through the fourth quarter of 2008 and into 2009, our capital will be committed to the drilling of wells on the Forth Berthold Indian Reservation in North Dakota. As part of this strategy, we have deferred our plans for drilling on other acreage in North Dakota and Montana that are outside the Bakken oil play and on prospect acreage that we have acquired in Wyoming. We intend to maintain a significant working interest in each well we drill and we intend to operate our wells in all possible cases.

        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. During the nine month period ended September 30, 2008, we incurred capital expenditures of approximately $11.9 million largely related to our oil and gas drilling operations. Except for wells currently in progress, these expenditures increased our full cost pool, but did not add significantly to our reserves. As of September 30, 2008, based on oil and gas prices of $87.81 per barrel of crude oil and $4.69 per Mcf of natural gas, the value of Kodiak's proved reserves as calculated under SEC guidelines did not support the costs included in the full cost pool. Consequently, the Company recorded an asset impairment of $15.5 million during the three month period ended September 30, 2008. The impairment primarily relates to a change in commodity prices and a revision of our previously recorded proved undeveloped locations (PUD).

•

In comparison, average prices received during the quarter ended September 30, 2008 were $107.47 per barrel of crude oil and $3.57 per Mcf of natural gas and our average prices received during October 2008 were $62.56 per barrel of crude oil and $3.59 per Mcf of natural gas.

•

As a result of the deteriorating commodity prices and the Company's strategy to focus its capital expenditures on the Bakken oil play in North Dakota, we reassessed all of our PUDs. Based on the uncertain timing of any potential drilling program on these PUDs and the current environment of lower commodity prices, the present value of these PUDs was deemed

17

non-commercial. Accordingly, we recorded an impairment charge for a significant portion of our previously recorded PUDs.

        Our working capital of approximately $18.7 million as of September 30, 2008 may not be sufficient to support all of our potential exploration opportunities in 2009, depending on the nature and extent of our final capital expenditure budget and the terms of potential joint venture arrangements into which the Company may enter. As our anticipated funds from operations are expected to provide only a limited amount of additional working capital, it is likely that we will need to obtain alternative sources of capital to fund our growth and development. We anticipate that we would seek to obtain additional funding either by means of debt or equity financings which, because of the current volatility of the capital and debt markets and the low price of our common stock, may not be available on reasonable terms, if at all. Alternatively, we will consider entering into additional joint venture agreements with other companies to enable us to continue our exploration drilling activities although reducing our working interest in those prospects. We cannot offer any assurance that we will be able to complete our anticipated 2009 capital obligations unless we are able to achieve one of the foregoing methods of financing those obligations, the availability of which cannot be assured.

Recent Developments

Vermillion Basin—Sweetwater County, Wyoming

        Drilling activities commenced in late August 2008 in the Vermillion Basin to further evaluate the Baxter shale at an approximate depth of 10,000 feet to 13,000 feet. Devon Energy Production Company, L.P., a wholly owned subsidiary of Devon Energy Corp. ("Devon"), operates the wells which are being drilled pursuant to the Vermillion Basin Exploration Agreement entered into with Devon during the first quarter of 2008. The intent of the 2008 drilling program is to obtain and evaluate data points from different locations within our acreage block. Based upon the results of this information, further drilling activity, contemplated as being horizontal drilling, and completion work will be continued in 2009.

        Initial exploration efforts are focused on two specific areas: the Horseshoe Basin Unit (HBU) located on the western edge of Kodiak's acreage and the Coyote Flats Federal Unit (CFU) located on the northern edge. Kodiak has an approximate 50% working interest in these wells

•

The CFU #1-8 well has been drilled to an approximate depth of 12,750 feet in the Baxter shale and extensive logging procedures were completed. After evaluation of all data this well may be drilled horizontally in 2009.

•

The HBU #1-4 well has been drilled to a vertical depth of approximately 11,700 feet and approximately 240 feet was cored in the target pay zones. Current exploration plans anticipate that this well will be reentered in 2009 and drilled horizontally through the targeted Baxter interval.

•

A second rig is drilling on the HBU #13-36 well. Intermediate casing has been set to 10,192 feet and coring work has been completed over 240 feet of the Baxter interval. This well is currently being drilled horizontally with a projected lateral of approximately 3,000 feet. Completion work on this well is projected to commence in 2009 after winter stipulations expire in the 2^nd quarter.

•

The CFU #14-36 well, which is an offset to Kodiak's North Trail State #4-36 well, is scheduled for drilling in the fourth quarter and is currently contemplated to be drilled horizontally in the Baxter Formation. The well may be completed in 2008, however the well is subject to lease stipulations. The program might be adjusted to be in compliance with the stipulations and completion work delayed into 2009.

18

•

The gathering pipeline and facilities have been installed to connect the HBU #5-3 well to production. Only the final lease facility construction remains to bring this well on production, which we anticipate to be completed by mid fourth quarter.

•

Acquisition of approximately 25 miles of 3-D seismic is currently being undertaken over a portion of the Horseshoe Basin Unit by the operator.

Williston Basin—Dunn County, North Dakota

        Our current drilling permit inventory includes thirteen approved well bores, with additional permitting in process. In an effort to minimize surface disturbance and to lower drilling costs, most of Kodiak's approved permits allow for the drilling of two wells per drilling pad location. Construction has been completed on two drill pads from which a total of three wellbores can be drilled. Construction is underway on an additional drill pad that will accommodate two wellbores. Kodiak recently received a Finding of no Significant Impact (FONSI) approval on three additional drilling permits encompassing six well bores. The associated Environmental Assessments (EA) are undergoing the customary 30-day comment period. Surveying has been completed and the scoping period is underway on six additional drill pads, with EA's to follow.

        Our exploration team continues its efforts to assemble an inventory of drilling permits in the prolific Bakken oil play. As of September 30, 2008, we owned an approximate 37,600 net acres under 53,200 gross leasehold acres on the Fort Berthold Indian Reservation (FBIR) in Dunn County, N.D. As of November 3, 2008, and giving effect to additional acreage acquired and the effect of the joint ventures discussed below we owned approximately 56,000 gross and 36,000 net acres under lease on the FBIR. These acreage totals include acquisitions subsequent to September 30, 2008 and reflect the recently signed participation agreement as discussed below. We operate all of our leasehold on the FBIR, excepting an approximate 7,000 net acres that are in a participating area previously established with another operator. Our exploration efforts target oil production from the middle member between the upper and lower Bakken shales that serve as the source rock for the existing hydrocarbons. The Three Forks/Sanish Formation that is directly below the lower Bakken shale is also a target of future exploration plans.

        Effective November 3, 2008, the Company entered into a letter agreement with a private, third-party oil and gas company to drill up to seven wells on certain of Kodiak's lands. The first two wells, the MC #16-34-2H and the MC #16-34H, are anticipated to be drilled under a participation agreement that will be executed prior to the spud date of the first well. Under this participation agreement, Kodiak will pay 20% of the drilling and completion costs associated with the first, third, fifth and seventh wells for its 60% WI and the joint venture partner will pay 80% of the wells' costs for its 40% interest. All other wells on the lands covered under the participation agreement will be drilled in proportion to the 60/40 percent working interest of each party. The first seven wells must be drilled within 30 months of the date of the participation agreement. By drilling the wells on a promoted basis, the third party will earn 40% under certain lands where Kodiak owns 100% working interest. Under the letter agreement, the total promote on the wells to be drilled will not exceed $8.5 million to the third party.

        Kodiak has taken control of its first new built drilling rig, which is presently being moved to North Dakota. As previously announced, the delivery of the first drilling rig was delayed. The delay provided an opportunity to obtain additional approved drilling permits, and, with new drilling results, more control over well-site selection. With winter's onset, locating the rig in the southwestern part of our leasehold should allow for easier rig mobilization and demobilization during the coming months. The rig is being delivered to the Moccasin Creek (MC) #16-34-2H (Kodiak operated and 60% working interest) drillsite and drilling will commence in a southeasterly direction following the rig mobilization. We anticipate that drilling will take 30-45 days. Assuming we encounter our expected results on the

19

initial well, the drilling rig is designed to skid a few feet and drilling will commence on a second wellbore in a northwesterly direction on the MC #16-34H (Kodiak operated and 60% working interest). Once the rig is moved from the first drilling pad, surface reclamation work will follow with completion of the wells anticipated to commence within 30 days subject to the availability of third party services. These first two wells fall under the terms of the participation agreement discussed above.

        Following these first two wells, the rig will be moved to other approved locations on a continuous drilling program, with Kodiak's working interest in most of the wells anticipated to be approximately 50%.

        Kodiak's second new built drilling rig appears to be on schedule with availability expected in the first quarter of 2009.

Three Forks/Sanish Potential

        Kodiak is monitoring the progress of the emerging Three Forks/Sanish oil play in the Williston Basin. The Three Forks/Sanish interval lies just below the lower Bakken shale and produces in various parts of the Basin. To the west and north of Kodiak's leasehold, several operators have drilled and completed wells in the Three Forks/Sanish formations. The Company intends to evaluate the Three Forks/Sanish formations with at least one exploratory well in 2009.

Stock Offering

        In August 2008 we completed a public offering of 6,000,000 shares of common stock with an exercised over-allotment issuance of an additional 820,000 shares of our common stock at a price of $2.75 per share. Including the exercise of the over-allotment option, the net proceeds of the offering, after deducting underwriting discounts and commissions and our offering expenses, were approximately $17.5 million.

Revolving Credit Facility

        On September 11, 2008, our wholly owned subsidiary, Kodiak Oil & Gas (USA) Inc., entered into the Credit Facility. The Credit Facility is secured by a first priority mortgage and security interest in, among other things, at least 80% of the PV10% value of our existing producing oil and gas properties and producing oil and gas properties hereafter acquired by the Company (including our subsidiaries), all of the stock or partnership interests of all direct or indirect subsidiaries of the Company, and accounts receivable, inventory, contract rights, and general intangibles of the Company (including that of our subsidiaries). See note 7 to the financial statements included in this Quarterly Report for more information on the Credit Facility.

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 about producer ability to ensure sufficient supply to meet increasing demand 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 have hedges of our commodity sales in place.

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

20

costs are summarized in the following table for the three and nine month periods ended September 30, 2008, and September 30, 2007.

		For the three months ended				For the nine months ended
		September 30, 2008		September 30, 2007		September 30, 2008		September 30, 2007
Sales Volume:
Gas (Mcf)			42,000		52,877		144,709		150,977
Oil (Bbls)			14,832		27,553		43,691		79,689
Production volumes (BOE)			21,832		36,366		67,809		104,852
Price:
Gas ($/Mcf)		$	3.57	$	4.28	$	7.45	$	4.97
Oil ($/Bbls)		$	107.47	$	71.65	$	103.18	$	61.44
Production costs ($/BOE):
	Lease operating expenses	$	31.06	$	5.25	$	36.16	$	5.73
	Production and property taxes	$	10.07	$	6.30	$	8.73	$	4.88
	Gathering, Transportation & Marketing	$	0.96	$	1.12	$	1.15	$	0.81

Results of Operations

For the Three Months Ended September 30, 2008 compared to the Three Months Ended September 30, 2007

        The Company reported a net loss for the three months ended September 30, 2008 of $17,959,649, compared to a net loss of $21,984,875 for the same period in 2007. The Company's net loss for the three months ended September 30, 2008 was largely due to an impairment expense charge of $15,500,000 and increased operating expenses as a result of workover and repair procedures in the amount of $343,000 related to our producing Bakken oil wells in McKenzie County, North Dakota.

	For the three months ended
	September 30, 2008			September 30, 2007
Financial Results
Total revenue	$	1,782,351		$	2,505,998
Total costs and expenses		19,742,000			24,490,873
Net loss	$	(17,959,649	)	$	(21,984,875	)
Diluted net loss per common share	$	(0.20	)	$	(0.25	)
Capital Resources and Liquidity
Cash and cash equivalents at end of the period	$	11,191,928		$	19,364,686
Net cash provided by (used in) operating activities	$	(4,803,130	)	$	(180,329	)
Capital expenditures—oil and gas properties excluding accruals and proceeds from divestitures	$	2,758,879		$	11,501,353
Adjusted EBITDA (see below discussion)	$	(461,635	)	$	815,569

21

Oil and Gas Revenue and Production

        Natural gas production volumes decreased 20% and oil production volumes decreased 46% for the three month period ended September 30, 2008, compared to the same period in 2007. Oil and natural gas production decreased due to workover operations on producing wells. Total gas price realizations decreased 17% to $3.57 per Mcf for the three month period ended September 30, 2008, compared to $4.28 per Mcf for the same period in 2007. Oil price realizations were $107.47 per barrel for the three month period ended September 30, 2008, compared to $71.65 for the same period in 2007. The net effect of the pricing and volume changes resulted in a decrease of oil and gas revenues of $456,365 to $1,743,884 for the three month periods ended September 30, 2008, compared to the same period in 2007.

Lease Operating Expenses

        The Company recorded workover, lease operating and production tax expense of $856,398 during the three month period ended September 30, 2008, as compared to $460,867 during the same period in 2007. In the third quarter of 2008, we completed workover operations on our producing Bakken oil wells in McKenzie County near the North Dakota and Montana state line. As part of this program we performed repair work on the casing of one well. This work was completed and the well is back on production. The net cost of approximately $343,000 related to the repair work was charged to oil and gas production costs and expenses in the third quarter of 2008 in addition to approximately $1,400,000 expensed in the first half of 2008.

Depletion, Depreciation and Amortization

        Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was $1,220,222 for the three month period ended September 30, 2008, compared to $2,036,384 for the same period in 2007. DD&A expense decreased during the quarter due to the reclassification of wells whose costs were previously classified as wells in progress thus increasing the amortization pool and the DD&A rate. This increase was partially offset by the reduced crude oil volume produced due to the workover operations on producing oil wells.

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. As of September 30, 2008, based on oil and gas prices of $87.81 per barrel and $4.69 per mcf, the full cost pool exceeded the ceiling by $15,500,000. An impairment charge of $15,500,000 was recorded during the three month period ended September 30, 2008. A similar impairment charge of $20,000,000 was recorded during the three month period ended September 30, 2007.

General and Administrative Expense

        The Company's general and administrative costs of $2,162,388 during the three months ended September 30, 2008, compares to $2,091,145 for the same period in 2007. Included in the general and administrative expense for this period is a stock-based compensation expense of $774,800 and $861,583 for 2008 and 2007, respectively, for options and restricted stock issued to officers, directors and employees. The overall increase in general and administrative costs is due to additional employees and office space in 2008 as compared to 2007, which costs were slightly offset by the lower stock compensation expense during the quarter. The decrease in stock compensation expense is primarily due

22

to the higher share price of the Company's common stock used for valuation at the time of grant in 2007 compared to the time of grant in 2008.

EBITDA

        In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gain on foreign currency, stock-based compensation expense and accretion of abandonment liability ("Adjusted EBITDA") as a key indicator of financial operating performance and as a measure of the ability to generate cash for operational activities, future capital expenditures, and servicing of borrowings under the Company's credit facility. The Company's Adjusted EBITDA decreased $1,277,204 to a loss of $461,635 for the three months ended September 30, 2008 from the same period in 2007. The decrease in Adjusted EBITDA was largely the result of decreased oil production as a result of workovers and repair work on producing wells. The repair costs increased operating expenses in the third quarter of 2008 and reduced Adjusted EBITDA by approximately $343,000. 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 EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies. Reconciliation between EBITDA and net income for the three months ended September 30, 2008 and 2007 is provided in the table below:

			Three months ended September 30, 2008			Three months ended September 30, 2007
Reconciliation of Adjusted EBITDA:
Net Loss			$	(17,959,649	)	$	(21,984,875	)
	Add back:
		Depreciation, depletion, amortization and accretion		1,220,222			2,036,384
		Asset impairment		15,500,000			20,000,000
		(Gain) / loss on foreign currency exchange		2,992			(97,523	)
		Stock based compensation expense		774,800			861,583
Adjusted EBITDA			$	(461,635	)	$	815,569

Results of Operations

For the Nine Months Ended September 30, 2008 compared to the Nine Months Ended September 30, 2007

        The Company reported a net loss for the nine months ended September 30, 2008, of $22,490,126 compared with a net loss of $36,888,954 for the same period in 2007. The Company's net loss for the nine months ended September 30, 2008, was significantly higher due to an impairment expense charge of $15,500,000 and by the reduced crude oil production and increased operating expenses as a result of

23

workover and repair procedures on its producing Bakken oil wells in McKenzie County, North Dakota (approximately $1.7 million).

	For the nine months ended
	September 30, 2008			September 30, 2007
Financial Results
Total revenue	$	5,744,578		$	6,970,655
Total costs and expenses		28,234,704			43,859,609
Net loss	$	(22,490,126	)	$	(36,888,954	)
Diluted net loss per common share	$	(0.25	)	$	(0.42	)
Capital Resources and Liquidity
Cash and cash equivalents at end of the period	$	11,191,928		$	19,364,686
Net cash provided by (used in) operating activities	$	(3,113,204	)	$	616,667
Capital expenditures—oil and gas properties excluding accruals and proceeds from divestitures	$	11,930,131		$	39,855,687
Adjusted EBITDA (see below discussion)	$	(1,124,015	)	$	2,081,844

Oil and Gas Revenue and Production

        Natural gas production volumes decreased 4% and oil production volumes decreased 45% for the nine month periods ended September 30, 2008, compared to the same period in 2007. Oil production decreased due to workover operations on producing wells. Total gas price realizations increased 50% to $7.45 per Mcf for the nine month period ended September 30, 2008, compared to $4.97 per Mcf for the same period in 2007. Oil price realizations were $103.18 per barrel for the nine month period ended September 30, 2008, compared to $61.44 for the same period in 2007. The net effect of the pricing and volume changes resulted in a decrease of oil and gas revenues of $60,807 to $5,585,861 for the nine months ended September 30, 2008, compared to the same period in 2007.

Lease Operating Expenses

        The Company recorded workover, lease operating and production tax expense of $3,121,967 during the nine months ended September 30, 2008, as compared to $1,197,639 during the same period in 2007. In the first nine months of 2008, we completed workover operations on our producing Bakken oil wells in McKenzie County near the North Dakota and Montana state line. As part of this program, we performed repair work on the casing of one well. This work was completed and the well is back on production. The net cost of approximately $1,700,000 related to the repair work was charged to oil and gas production costs and expenses in the first nine months of 2008.

Depletion, Depreciation and Amortization

        Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was $3,104,298 for the nine month period ended September 30, 2008, compared to $4,062,397 for the same period in 2007. DD&A expense decreased during the period due to the reclassification of wells whose costs were previously classified as wells in progress thus increasing the amortization pool and the DD&A rate. This increase was partially offset by the reduced crude oil volume produced due to the workover operations on producing oil wells.

24

Impairment

        An impairment charge of $15,500,000 was recorded during the nine month period ended September 30, 2008. Asset impairment of $34,000,000 was charged during the nine months ended September 30, 2007.

General and Administrative Expense

        The Company's general and administrative costs were $6,488,938 during the nine months ended September 30, 2008, compared to $5,380,549 for the same period in 2007. Included in the general and administrative expense for this period is a stock-based compensation expense of $2,742,312 and $1,689,377 for 2008 and 2007, respectively, for options and restricted stock issued to officers, directors and employees. The increase to the stock-based compensation charge is the result of options and restricted stock granted subsequent to September 30, 2007, and the impact to stock-based compensation expense for the difference between actual forfeitures and assumed forfeitures when the awards were granted. The overall increase in general and administrative expenses is due in part to the Company's increased staffing requirements and level of activity. The Company currently has eighteen full time and three contract employees compared to sixteen full time and one part time employee in September 2007.

EBITDA

        In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gain on foreign currency and stock-based compensation ("Adjusted EBITDA") as a key indicator of financial operating performance and as a measure of the ability to generate cash for operational activities, future capital expenditures, and servicing of borrowings under the Company's credit facility. The Company's Adjusted EBITDA decreased $3,205,859 to a loss of $1,124,015 for the nine months ended September 30, 2008 from the same period in 2007. The decrease in Adjusted EBITDA was largely the result of decreased oil production as a result of workovers and repair work on producing wells. The repair costs increased operating expenses in the first nine months of 2008 and reduced Adjusted EBITDA by approximately $1.7 million. 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 EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures

25

employed by other companies. Reconciliation between EBITDA and net income for the nine months ended September 30, 2008 and 2007 is provided in the table below:

			Nine months ended September 30, 2008			Nine months ended September 30, 2007
Reconciliation of Adjusted EBITDA:
Net Loss			$	(22,490,126	)	$	(36,888,954	)
	Add back:
		Depreciation, depletion, amortization and accretion		3,104,298			4,062,397
		Asset impairment		15,500,000			34,000,000
		(Gain)/loss on foreign currency exchange		19,501			(780,976	)
		Stock based compensation expense		2,742,312			1,689,377
Adjusted EBITDA			$	(1,124,015	)	$	2,081,844

Liquidity and Capital Resources

	For the three months ended September 30,						For the nine months ended September 30,
	2008			2007			2008			2007
Capital Resources and Liquidity
Cash and cash equivalents at end of the period	$	11,191,928		$	19,364,686		$	11,191,928		$	19,364,686
Net cash provided by (used in) operating activities		2,056,788			(180,329	)		(3,113,204	)		616,667
Net cash used in investing activities		(2,777,107	)		(11,550,887	)		(9,501,756	)		(40,103,394	)
Net cash provided by financing activities		10,712,820			147,150			10,791,570			382,150
Net cash flow		9,992,501			(11,584,066	)		(1,823,390	)		(39,104,577	)

        Kodiak ended the third quarter of 2008 with cash and cash equivalents of $11.2 million down from $13.0 million at year-end 2007. Total working capital was $18.7 million at September 30, 2008, as compared to $10.2 million at December 31, 2007. As of September 30, 2008, we had prepaid $6.9 million towards the cost of tubular goods. Cash flow used in operating activities for the first nine months of 2008 was $3.1 million which was largely the result of a $1.7 million workover expenditure. Cash used as capital expenditures for our oil and gas activities totaled $11.9 million for the first nine months of 2008 and was offset by $2.4 million in proceeds from sales of oil and gas properties. We have acquired or made deposits on projected tubular goods requirements for part of our drilling program. Net cash provided by financing activities for the first nine months of 2008 was $10.8 million which includes our common stock offering in August 2008 of $17.5 million (net of issuance costs) less $6.9 million prepaid on tubular goods for seven wells.

        Kodiak's results of operations and financial condition are significantly affected by the success of our exploration and land leasing activity, the resulting production and reserves, oil and natural gas commodity prices, and the costs related to operating our properties. In the first nine months of 2008, our oil and gas revenue decreased by 1% from $5.6 million during the first nine months of 2007 to $5.5 million. This decrease is largely the result of the decrease in our crude oil production as a result of oil producing wells that were shut in for completion, repair and workover procedures partially offset by increased prices received for both our crude oil and natural gas production. Total costs and expenses decreased to $28.2 million in the first nine months of 2008 from $43.8 million in the first nine months of 2007 largely due to an asset impairment in 2007 of $34.0 million related to the full cost ceiling test in 2007 versus a $15.5 million asset impairment charge in 2008 also related to the full cost ceiling test

26

as of September 30, 2008. The increase in general and administrative expenses included an increase in the non-cash charge for stock based compensation from $1.7 million during the first nine months of 2007 to the $2.7 first nine months of 2008. This increase is due to additional options and restricted stock issued since implementing the 2007 Plan, and a change in the forfeiture rate assumed for future vested options.

        Due to our oil and natural gas exploration program, we have experienced, and expect to continue to experience, substantial working capital requirements. As a result of our agreement with Devon, we have maintained a significant level of activity in the Vermillion Basin, without requiring capital expenditures. Based on our current exploration program and depending on the success in this play, we anticipate additional capital requirements after the second quarter of 2009. At this time we cannot assess our 2009 requirements in the area until we evaluate the results of the current drilling activity discussed above. By reducing the immediate capital requirements of our Vermillion Basin exploration and other areas in Wyoming and Montana, we intend to allocate our existing capital to the Bakken oil play on the FBIR in North Dakota. Over the past two years we have entered into exploration agreements with three separate joint venture partners in this play. Two of the agreements have been previously announced and primarily involved the sharing of lease acquisition with drilling and completion dollars being incurred in proportion to each parties respective working interest. The third exploration agreement which was recently announced involves a third party oil and gas company that will pay a disproportionate share of drilling and completion costs to earn a proportionate 40% working interest in certain lands where Kodiak had acquired a 100% working interest and were not subject to any previous agreements. This agreement requires the third party to pay 80% of the costs to drill and complete the first well to earn a 40% working interest in the "promoted well". The costs for the next well drilled on acreage involving this joint venture would be drilled in proportion to each parties working interest "non-promoted". This program will alternate between a "promoted" well and a "non-promoted" well through the seventh well drilled on lands within the exploration agreement, at which time all future wells will be drilled in proportion to each party's working interest. In no event shall such "promoted" interest exceed $8.5 million to the third party. The first two wells that we drill on the FBIR will be subject to this agreement. Through these agreements we have been able to spread our working interest over a larger geographic area while still maintaining significant working interests ranging from 50% to 70% working interest in the lands.

        In the first nine months of 2008, we incurred capital expenditures of approximately $9.5 million, net of proceeds from property divestitures and our agreement with Devon. As of September 30, 2008, our working capital was $18.7 million and we had no long-term debt. On September 11, 2008, the Company secured a line of credit with a bank which provides a borrowing base as of September 30, 2008 of $5.0 million. We project our capital expenditures in the Bakken oil play to be approximately $35 to $40 million through 2009. The price that we receive for our products cannot be predicted and the results of our exploration efforts are also not predictable. However, using current prices and projections we anticipate funding these expenditures through our existing working capital, anticipated production, and our unused line of credit. In the event that the economic parameters of the play area do not justify continued drilling we will adjust our drilling schedule.

        We believe that we may need to obtain additional sources of capital to fund further growth and development, the amount and timing of which will depend on the success and timing of our exploration activities. We anticipate that we would seek to obtain additional funding either by means of debt or equity financings or by entering into additional joint venture agreements, the availability of which there can be no assurance.

        Our ability to fund our operations in future periods will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot be certain that additional funding will be available on

27

acceptable terms, or at all. If we are unable to raise additional capital when required or on acceptable terms, we may have to significantly delay, scale back or discontinue our drilling or exploration program, seek to enter into additional joint venture arrangements with third parties, or seek to sell one or more of our properties. A significant delay in obtaining additional financing would have a material adverse effect on our business.

Oil and Gas Properties

        As of September 30, 2008, we had several hundred lease agreements representing approximately 169,700 gross and 101,800 net acres, primarily in the Green River and Williston Basins.

        As of September 30, 2008, we had acquired approximately 53,200 gross acres and 37,600 net acres in the Bakken oil play in Dunn County, North Dakota. The majority of our lands in this area are administered by the Bureau of Indian Affairs on behalf of the individual members of the Three Affiliated Tribes of the Fort Berthold Indian Reservation. Typically these lands are acquired through a private negotiation with the individual land owners or the Three Affiliated Tribes and have a primary lease term of five years. The land owner typically retains an 18% landowner royalty. In most cases, these lands require an annual delay rental of $2.50 per net acre. We have not yet conducted any drilling operations in our Bakken oil play on the FBIR, but plan to commence our first well in the fourth quarter of 2008.

        Our leasehold interests in the Vermillion Basin total approximately 42,900 gross and 16,100 net acres. The area of mutual interest ("AMI") with Devon will expire on January 1, 2013, unless extended by mutual agreement of both parties. Each party has agreed to an equal share of any interest or lease acquired within the participating area. We commenced drilling under this agreement during the third quarter of 2008.

        In January 2008, we completed the sale of 4,144 gross and net acres in an exploratory Mancos shale gas prospect located in the Sand Wash Basin in Moffat County, Colorado for $1.2 million. We retained a 5% overriding royalty in these properties as well as 100% working interest ownership in the remaining 3,770 acres. We believe the remaining acreage is prospective for production from the Mancos shale and Niobrara Formation at a shallower depth than that divested.

        The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of September 30, 2008.

	Undeveloped Acreage(1)				Developed Acreage(2)				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Green River Basin
Wyoming(3)		43,606		18,321		1,400		848		45,006		19,169
Colorado		7,419		4,986		0		0		7,419		4,986
Williston Basin
Montana		36,661		21,948		800		400		37,461		22,348
North Dakota		64,864		43,295		3,040		1,800		67,904		45,095
Other Basins
Wyoming		11,930		10,243		0		0		11,930		10,243
Acreage Totals		164,480		98,794		5,240		3,048		169,720		101,842

(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.

28

(3)

Excludes 10,261 gross (6,127 net) acres that can be earned pursuant to existing farm-in agreements.

Capital Expenditures

        Our revised budgeted net capital expenditures are expected to be between $22 million and $23 million in 2008. The following table sets forth our capital expenditures for the nine months ended September 30, 2008 and our planned capital expenditures for our principal properties in 2008. Net capital expenditures include both cash and accrued expenditures and are net of proceeds from divestitures. The 2008 estimated expenditures do not include the costs to drill additional wells that could help further evaluate our properties in the Vermillion Basin. These wells are to be drilled at the sole cost of Devon under the Devon Agreement, with such drilling commencing in the third quarter of 2008.

		Net Capital Expenditures for the Nine Months ended September 30, 2008 ($000)(1)		Total 2008 Revised Estimated Net Capital Expenditures ($000)(1)
Project Location
Wyoming
Vermillion Basin wells and related infrastructure		$	102	$	743
	Other Wyoming wells and related infrastructure		79		(845	)
Acreage/Seismic			257		1,350
Total Wyoming		$	438	$	1,248
Williston Basin
Mission Canyon/Red River wells and related infrastructure			169		1,127
Bakken wells and related infrastructure			2,425		19,696
Acreage/Seismic			4,898		621
Total Williston Basin		$	7,492	$	21,444
Total All Areas		$	7,930	$	22,692

(1)

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

        As is described elsewhere, we believe proceeds from our common stock offering provides sufficient capital to complete our 2008 capital expenditure program, however, we do not currently have sufficient working capital to continue projected capital expenditures expected for our 2009 capital expenditure program and to provide for our continuing negative cash flow from operating activities. We anticipate that we would seek to obtain additional funding either by means of debt or equity financings which, because of the current volatility of the capital and debt markets and the low price of our common stock, may not be available on reasonable terms, if at all. Alternatively, we will consider entering into additional joint venture agreements with other companies to enable us to continue our exploration drilling activities although reducing our working interest in those prospects. We cannot offer any assurance that we will be able to complete our anticipated 2009 capital obligations unless we are able to achieve one of the foregoing methods of financing those obligations, the availability of which cannot be assured.

Off-Balance Sheet Arrangements

        Other than standard operating leases, we do not have any off-balance sheet financing arrangements at September 30, 2008 and December 31, 2007.

29

Critical Accounting Policies and Estimates

        We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2007.

Recently Issued Accounting Pronouncements

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

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

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

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

        In June 2008, the FASB issued FSP No. EITF 03-6-1, "Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities," (FSP EITF 03-6-1). FSP EITF 03-6-1 states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share pursuant to the two-class method. FSP EITF 03-6-1 becomes effective for the Company on January 1, 2009. Management has determined that the adoption of FSP EITF 03-6-1 will not have an impact on the Financial Statements.

30

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 approximately a $144,709 change in our gross gas production revenue. A $1.00 per barrel change in the market price of oil will result in approximately a $43,691 change in our gross oil production revenue. The impact on any potential sale of property cannot be readily determined.

Interest Rate Fluctuations

        We currently maintain a portion of our available cash in redeemable short term investments, classified as cash equivalents, and our reported interest income from these short term investments could be adversely affected by any material changes in US dollar interest rates. A 1% change in the interest rate would have approximately a $91,553 annual impact if all of our cash, as of September 30, 2008, was invested in interest bearing notes.

ITEM 4.    CONTROLS AND PROCEDURES

        Under the supervision and with the participation of our management, we evaluated the design and operation 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, 2008. On the basis of this review, our management concluded that our disclosure controls and procedures are effectively designed to give reasonable assurance that the information we are required to disclose in reports that we file 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. Additionally, our CEO and CFO have concluded, as of September 30, 2008, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

        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.

31

PART II—OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

        None.

ITEM 1A.    RISK FACTORS

        Other than the following update, there have been no material changes to the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2007, as filed with the SEC on March 14, 2008. The risk factors disclosed here and in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, in addition to the other information set forth in this quarterly report, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

        The risk factor update is as follows:

Risks Related to the Company

We have a recent history of negative reserve revisions.

        We have a recent history of negative reserve revisions that occurred during the current year and during the last two fiscal years. Specifically, our September 30, 2008 oil and natural gas reserves reflected a downward revision of the December 31, 2007 reserves in the amount of approximately 348,000 BOE primarily as a result of the revision of reserves associated with proven undeveloped reserves. Our December 31, 2007 natural gas reserves reflected a downward revision of the December 31, 2006 reserves in the amount of 1.1 BCF, primarily as a result of the revision of reserves associated with the underperformance of one Vermillion Basin exploratory well. Our December 31, 2006 natural gas reserves reflected a downward revision of the December 31, 2005 reserves of 2.8 BCF, primarily as a result of the revision of reserves associated with our decision to discontinue exploration and development of our coalbed methane properties. Due to the imprecise nature of estimating natural gas and oil reserves as well as the potential volatility in natural gas and oil prices and their effect on the carrying value of our natural gas and oil properties, negative reserve revisions in the future may also be required as a result of factors that may negatively affect the present value of proved natural gas and oil reserves. These factors can include volatile natural gas and oil prices, downward revisions in estimated proved natural gas and oil reserve quantities, limited classification of proved reserves associated with successful wells and unsuccessful drilling activities. When reserves are found to be materially lower than we had estimated and reported, our prospects and stock price could be adversely affected.

The deterioration of global economic and financial conditions and an extended decline in the price of oil and natural gas would negatively impact our business, financial condition and results of operations.

        The global economic and financial crisis could lead to an extended national or global economic recession. A slowdown in economic activity caused by a recession would likely reduce national and worldwide demand for oil and natural gas and result in lower commodity prices. Substantial decreases in oil and natural gas prices could have a material adverse effect on our business, financial condition and results of operations, could limit our access to liquidity and credit and could hinder our ability to fund our development program. The inability to execute our development program could also lead to low production and reserve growth.

32

We will require significant additional working capital, which may not be available to us on favorable terms, or at all.

        Our working capital of $18.7 million as of September 30, 2008 may not be sufficient to support all of our potential exploration opportunities in 2009. Future acquisitions and future exploration, development and production activities will require a substantial amount of additional working capital and cash flow. We expect that our current cash balances and cash flow from operations will be sufficient only to provide a limited amount of working capital, and the revenues generated from our properties will not alone be sufficient to fund our operations or planned growth. These conditions may require us to seek alternative sources of capital by means of entering into joint ventures with other exploration and production companies or by undertaking financing activities. However, future financing may not be available in amounts or on terms acceptable to us, if at all. If we borrow additional funds, we will likely be obligated to make periodic interest or other debt service payments and may be subject to additional restrictive covenants. Should we elect to raise additional capital through the issuance and sale of equity securities, the sales may be at prices below the market price of our stock, and our shareholders may suffer significant dilution. Our failure to obtain financing on a timely basis or on favorable terms could result in the loss or substantial dilution of our interests in our properties.

If credit and capital markets worsen, then we may not be able to obtain funding on acceptable terms. The inability to obtain funding could deter or prevent us from meeting our future capital needs to fund our capital expenditure program.

        Capital and credit markets have experienced unprecedented volatility and disruption during the third quarter of 2008 and continue to be unpredictable. Given the current levels of market volatility and disruption, the availability of funds from those markets has diminished substantially. Further, arising from concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of accessing the credit markets has increased as many lenders have raised interest rates, enacted tighter lending standards or altogether ceased to provide funding to borrowers. Additionally, even if lenders continue and are able to provide funding to borrowers, interest rates may rise in the future and therefore increase the cost of outstanding borrowings that we may incur under our revolving credit facility.

        Moreover, we may be unable to obtain adequate funding under our current credit facility. Our borrowing base under our current credit facility is redetermined semiannually. Our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors. If oil and natural gas prices significantly decline for an extended period of time, our lenders could redetermine the borrowing base by evaluating our reserves at substantially lower oil and natural gas prices. Such determination could result in a negative revision to our proved reserve value and reduce our borrowing base.

        Due to these capital and credit market conditions, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our capital expenditure program, grow our existing business through acquisitions or joint ventures or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to our Common Stock

Future sales or other issuances of our common stock could depress the market for our common stock.

        On July 14, 2008, we filed a shelf registration statement on Form S-3, which was declared effective by the SEC on July 24, 2008. Under this shelf registration statement, we have raised funds and may

33

seek to raise additional funds through one or more public offerings of our common stock, in amounts and at prices and terms determined at the time of the offering. Any sales of large quantities of our common stock could reduce the price of our common stock, and, to the extent that we raise additional capital by issuing equity securities pursuant to our effective shelf registration statements or otherwise, our existing stockholders' ownership will be diluted. In August 2008, the Company issued 6,820,000 shares of common stock in a public offering for gross proceeds of approximately $18.8 million. The Company paid approximately $1.2 million in commissions and expenses.

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

        None.

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

        None.

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

        None.

ITEM 5.    OTHER INFORMATION

        None.

ITEM 6.    EXHIBITS

Exhibit Number	Description
10.1	Credit Agreement between Kodiak Oil & Gas (USA) Inc. and Bank of the West, dated as of September 11, 2008
10.2	ISDA Master Agreement between Kodiak Oil & Gas (USA) Inc. and Bank of the West, dated as of September 30, 2008
31.1	Certification of the Principal Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of the Principal Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002
32.1	Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350
32.2	Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350

34

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, 2008	/s/ LYNN A. PETERSON Lynn A. Peterson President and Chief Executive Officer
November 5, 2008	/s/ KEITH DOSS Keith Doss Chief Financial Officer (principal financial officer)

35