Kodiak Oil & Gas 10Q 2010 Q3 Quarterly report

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TABLE OF CONTENTS

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, 2010

Commission File No. 001-32920

(Exact name of registrant as specified in its charter)


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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer o		Accelerated filer ý		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

148,636,455 shares, no par value, of the Registrant's common stock were issued and outstanding as of November 2, 2010.

Table of Contents

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	23
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	38
ITEM 4.	CONTROLS AND PROCEDURES	39
PART II—OTHER INFORMATION		39
ITEM 1.	LEGAL PROCEEDINGS	39
ITEM 1A.	RISK FACTORS	39
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	42
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	42
ITEM 4.	RESERVED	42
ITEM 5.	OTHER INFORMATION	42
ITEM 6.	EXHIBITS	43
SIGNATURES		44

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PART 1—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

				September 30, 2010			December 31, 2009

ASSETS
Current Assets:
	Cash and cash equivalents			$	61,827		$	24,885
	Accounts receivable
		Trade			6,063			2,563
		Accrued sales revenues			3,540			1,909
Inventory, prepaid expenses and other					18,519			7,648

			Total Current Assets		89,949			37,005

Oil and gas properties (full cost method), at cost:
		Proved oil and gas properties			152,849			123,259
		Unproved oil and gas properties			24,517			12,068
		Wells in progress			13,276			2,691
Facilities					500			—
	Less-accumulated depletion, depreciation, amortization, accretion and asset impairment				(100,562	)		(95,782	)

	Net oil and gas properties				90,580			42,236

Property and equipment, net of accumulated depreciation of $351 in 2010 and $285 in 2009					334			442
Deferred financing costs, net of amortization of $34 in 2010					326			—

Total Assets				$	181,189		$	79,683

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
	Accounts payable and accrued liabilities			$	27,104		$	7,743
	Advances from joint interest owners				1,642			952
	Commodity price risk management liability				448			—

			Total Current Liabilities		29,194			8,695
Noncurrent Liabilities:
	Commodity price risk management liability				653			—
	Asset retirement obligation				1,504			1,060

			Total Liabilities		31,351			9,755

Commitments and Contingencies—Note 5
Stockholders' Equity:
	Common stock—no par value; unlimited authorized
	Issued and outstanding: 148,360,910 as of September 30, 2010 and 118,879,931 shares as of December 31, 2009
	Contributed surplus				253,738			175,791
	Accumulated deficit				(103,900	)		(105,863	)

			Total Stockholders' Equity		149,838			69,928

Total Liabilities and Stockholders' Equity				$	181,189		$	79,683

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)

(Unaudited)

			Three months ended September 30,						For the nine months ended September 30,

			2010			2009			2010			2009
Revenues:
	Gas production		$	167		$	129		$	599		$	541
	Oil production			7,964			3,603			19,374			5,959
	Loss on risk management activities			(1,149	)		—			(1,101	)		—
	Interest income & other			12			7			28			44

		Total revenue		6,994			3,739			18,900			6,544

Operating expenses:
	Oil and gas production			1,705			740			4,435			1,233
	Depletion, depreciation, amortization and accretion			2,081			1,050			4,932			1,938
	General and administrative			2,783			1,958			7,491			5,548

		Total operating expenses		6,569			3,748			16,858			8,719

Interest Expense				64			—			79			^—

Net income (loss) attributable to common shares			$	361		$	(9	)	$	1,963		$	(2,175	)

Net income per common share:
	Basic		$	0.00		$	0.00		$	0.02		$	(0.02	)

	Diluted		$	0.00		$	0.00		$	0.02		$	(0.02	)

Weighted average shares outstanding:
	Basic			133,356,932			104,832,898			123,929,455			100,101,589

	Diluted			134,947,407			104,832,898			125,533,666			100,101,589

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

			For the nine months ended September 30,

			2010			2009
Cash flows from operating activities:
	Net income (loss)		$	1,963		$	(2,175	)
Reconciliation of net income (loss) to net cash provided by operating activities:
		Depletion, depreciation, amortization and accretion		4,932			1,938
		Change in fair value of commodity price risk management activities, net		1,101			—
		Stock based compensation		2,778			2,147
	Changes in current assets and liabilities:
		Accounts receivable-trade		(3,501	)		(1,905	)
		Accounts receivable-accrued sales revenue		(1,631	)		(1,504	)
		Prepaid expenses and other		(983	)		2,808
		Accounts payable and accrued liabilities		8,160			3,749

Net cash provided by operating activities				12,819			5,058

Cash flows from investing activities:
		Oil and gas properties		(45,453	)		(15,528	)
		Facilities, equipment & other		(706	)		8
		Prepaid tubular goods		(4,528	)		(2,928	)
		Restricted investment		—			246

Net cash (used in) investing activities				(50,687	)		(18,202	)

Cash flows from financing activities:
		Borrowings under credit facility		7,500			—
		Repayments under credit facility		(7,500	)		—
		Proceeds from the issuance of common shares		79,682			7,425
		Debt and share issuance costs		(4,872	)		(108	)

Net cash provided by financing activities				74,810			7,317

Net change in cash and cash equivalents				36,942			(5,827	)
Cash and cash equivalents at beginning of the period				24,885			7,581

Cash and cash equivalents at end of the period			$	61,827		$	1,754

Supplemental cash flow information
	Oil & gas property accrual included in Accounts payable and accrued liabilities		$	3,462		$	1,380

	Asset retirement obligation		$	425		$	175

	Tubular inventory accrual included in accounts payable		$	9,030		$	—

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization

Description of Operations

Kodiak Oil & Gas Corp. (together with its subsidiary, "Kodiak," "we" or the "Company") is an independent energy company engaged in the exploration, exploitation, development, acquisition and production of crude oil and natural gas entirely in the western United States. The common shares of the Company are listed for trading on the NYSE Amex LLC and the Company's corporate headquarters are located in Denver, Colorado, USA.

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

Note 2—Basis of Presentation and Significant Accounting Policies

Basis of Presentation

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

Liquidity and Capital Resources

On August 18, 2010, we closed a public offering of 28,750,000 shares of common stock, including the full exercise of the underwriters' over-allotment option of 3,750,000 shares. All shares were sold at a price of $2.75 per share. The net proceeds of the offering, after deducting underwriting discounts and commissions and our estimated offering expenses, were $74.6 million.

On October 19, 2010, the Company and its subsidiary, Kodiak USA, entered into a definitive agreement (the "Asset Purchase Agreement") to acquire approximately 14,500 net acres of Bakken/Three Forks leasehold and related producing properties in the Williston Basin of North Dakota ("Acquisition"). The consideration for the Acquisition is expected to include $99 million in cash and the issuance of 2.75 million shares of common stock to the seller. In the event we fail to satisfy certain conditions precedent to the issuance of such shares, Kodiak USA will be obligated to pay $11 million in cash to Seller in lieu of us issuing the shares. Upon signing the Purchase Agreement, Kodiak USA deposited $5.5 million in escrow. In the event Kodiak USA fails to close the Acquisition as a result of its material breach, Kodiak USA will forfeit such deposit.

Our total capital expenditures for 2010, including expected cash consideration related to the Acquisition ($99 million) and our other expected capital expenditures ($75 million), are expected to be approximately $175 million. However, in the event Kodiak USA is required to fund the additional $11 million in cash in lieu of us issuing the 2.75 million shares in connection with the Acquisition, our capital expenditures could be as high as $186 million. Of our total 2010 potential capital expenditures, up to $133 million is estimated to be spent in the fourth quarter of 2010 ($110 million for the acquisition and $23 million for drilling, completion and acreage acquisition), assuming no shares are issued in the acquisition. We expect to fund such remaining 2010 capital expenditures through a combination of the following sources of capital:

•: New term debt: We are in advanced discussions to establish a senior secured second lien term loan with a total commitment of $40 million, all of which we would apply toward our remaining

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

2010 capital expenditures. We have a commitment letter for this facility but standard conditions and requirements must be satisfied before closing, and there can be no assurances as to the availability of these funds.

•: Expanded revolving debt: We are in advanced discussions to expand our existing revolving borrowing base from $20 million to $50 million as a result of our drilling and completion activities and, to a lesser extent, due to the oil and gas reserves included in the Acquisition. As of September 30, 2010, there were no outstanding borrowings under this facility. Although we have a commitment letter from the lender to increase the facility, certain conditions and requirements must be met before closing, and there can be no assurances as to the availability of these funds.
•: Existing working capital and anticipated cash flow from operations. We expect to fund the balance of the 2010 capital expenditure budget not covered through the proposed new term debt and expanded revolving debt through existing working capital and expected cash flow from operations. As of September 30, 2010, our working capital totaled $61 million.

We cannot give assurances that either our cash flow from operations or increases in our available borrowings will be sufficient to fund our anticipated capital expenditures, including the funding of the Acquisition. If our existing and potential sources of liquidity through operating cash flows or expanded available borrowings are not sufficient to undertake our planned capital expenditures, we may not be able to close the Acquisition and may be further required to alter our drilling program, pursue joint ventures with third parties, sell interests in one or more of our properties or sell common shares or debt securities. There can be no assurance that any such transactions can be completed or that such transactions will satisfy our capital requirements. If we are not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our expenditures or restructure our operations, and we would be unable to implement our planned exploration and drilling program.

Use of Estimates in the Preparation of Financial Statements

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

The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

estimates under different assumptions or conditions, we believe that our 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.

Inventory, Prepaid Expenses and Other

Included in inventory, prepaid expenses and other are deposits made on orders of tubular goods and surface equipment required for the Company's drilling program. As of September 30, 2010, this amount was approximately $18.2 million (consisting of $8.2 million of tubular goods and surface equipment that are inventoried in third-party yards and $10.0 million of deposits for tubular goods that will be delivered over the next 12 months or at such time that the tubular goods are required). In respect of the $10.0 million tubular goods deposit, as of September 30, 2010, the Company estimates that an additional $10.1 million will be paid to complete the purchase and the deposits would be subject to forfeit if the purchases are not completed. At December 31, 2009, the Company had $7.3 million in tubular goods and surface equipment. The cost basis of the tubular goods is either depreciated as a component of oil and gas properties once the inventory is used in drilling operations or billed to our partners through joint interest billings. The Company records tubular goods inventory at the lower of cost or market value. As of September 30, 2010, and December 31, 2009, respectively, the Company's analysis of the difference between cost compared to market values for tubular goods not designated for specific wells was not deemed material.

Concentration of Credit Risk

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

The Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. 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 and costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves as determined by the Company's engineers and prepared (annually) by independent petroleum engineers. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The unproved properties are reviewed quarterly for impairment. When proved reserves are assigned or the unproved 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.

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

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

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

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations. Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues is computed by applying current prices of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. There was no tax benefit or expense included in our ceiling test, due to the fact that future net revenues are exceeded by the tax basis of the properties involved and the Company's existing net operating losses ("NOLs"). We expect that all of our NOLs will be realized within future carryforward periods. All of the Company's operations, and resulting NOLs, are attributable to our oil and gas assets.

There were no impairment charges recognized for the nine month periods ended September 30, 2010 and 2009.

Wells in Progress

Wells in progress at September 30, 2010 and December 31, 2009 represent the costs associated with wells that have not reached total depth or been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test. The costs for these wells are then transferred to proved property when the wells are completed and the costs become subject to depletion and the ceiling test calculation in future periods.

Impairment of Long-lived Assets

The Company's unproved properties are evaluated quarterly for the possibility of impairment. In the nine month period ended September 30, 2010 and 2009, no unproved properties were impaired.

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.

Deferred Financing Costs

As of September 30, 2010, the Company recorded deferred financing costs of $360,000 related to the closing of its credit facility (see Note 6). Deferred financing costs include origination, legal and

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

engineering fees incurred in connection with the Company's credit facility, which are being amortized over the four-year term of the credit facility. The Company recorded amortization expense of $34,000 (which includes the expensing of all remaining deferred financing costs from the Company's previous credit facility) in the nine month period ended September 30, 2010.

Commodity Derivative Instrument

Through its wholly-owned affiliate Kodiak USA, the Company has entered into commodity derivative contracts, as described below. The Company has utilized swaps or "no premium" collars to reduce the effect of price changes on a portion of our future oil production. A collar requires us to pay the counterparty if the market price is above the ceiling price and requires the counterparty to pay us if the market price is below the floor price. A swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price. The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts are currently with two counterparties and the Company is a guarantor of Kodiak USA. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with each counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company's commodity derivative contracts as of September 30, 2010 are summarized below:

Contract Type	Counterparty	Basis	Quantity(Bbl/d)	Strike Price ($/Bbl)	Term

Collar	BP North America	NYMEX	200	$70.00/$90.00	Mar 1 - Dec 31, 2010
Collar	Wells Fargo Bank, N.A.	NYMEX	400	$75.00/$89.20	Jan 1 - Dec 31, 2011
Collar	Wells Fargo Bank, N.A.	NYMEX	200 - 500	$70.00/$95.56	Jan 1 - Dec 31, 2011
Collar	Wells Fargo Bank, N.A.	NYMEX	400	$70.00/$95.56	Jan 1 - Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	600	$77.89	Oct 1 - Dec 31, 2010

Subsequent to September 30, 2010, the Company entered into additional commodity derivative contracts which are summarized below:

Contract Type	Counterparty	Basis		Strike Price ($/Bbl)		Term

Swap	Wells Fargo Bank, N.A.	NYMEX	136	$	88.30	Jan 1 - Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	427	$	88.30	Jan 1 - Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	360	$	88.30	Jan 1 - Dec 31, 2014
Swap	Wells Fargo Bank, N.A.	NYMEX	317	$	88.30	Jan 1 - Sept 30, 2015

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

		Fair Value at

Underlying Commodity	Location on Balance Sheet	September 30, 2010		December 31, 2009
Crude oil derivative contract	Current liabilities	$	448	$	—
Crude oil derivative contract	Noncurrent liabilities	$	653	$	—

The amount of gain (loss) recognized in income related to our derivative financial instruments was as follows (in thousands):

		Three months ended September 30,					Nine months ended September 30,

		2010			2009		2010			2009
Unrealized loss on oil contracts		$	(1,149	)	$	—	$	(1,101	)	$	—
Realized loss on oil contracts		$	—		$	—	$	—		$	—

	Loss on risk management activities	$	(1,149	)		0	$	(1,101	)		0

Unrealized gains and losses resulting from derivatives are recorded at fair value on the condensed consolidated balance sheet and changes in fair value are recognized in the unrealized gain (loss) on risk management activities line on the condensed consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the condensed consolidated statement of income. There were no realized gains or losses recorded for the nine months ending September 30, 2010.

Fair Value of Financial Instruments

The Company's financial instruments, other than the derivative instrument discussed above, including cash and cash equivalents, are carried at cost, which approximates fair value due to the short-term maturity of these instruments.

Revenue Recognition

The Company records revenues from the sales of natural gas and crude oil when they are produced and sold. The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners' gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company's over and under produced gas balancing positions are considered in the Company's proved oil and gas revenues. Gas imbalances at September 30, 2010 and December 31, 2009 were not significant.

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Computation of Net Income (Loss) Per Share

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

The table below sets forth the computations of basic and diluted net income (loss) per share for the three and nine months ended September 30, 2010 and September 30, 2009 (in thousands, except share amounts).

		For the three months ended September 30,						For the nine months ended September 30,

		2010			2009			2010			2009
Numerator:
Basic net income (loss)		$	361		$	(9	)	$	1,963		$	(2,175	)
	Dilutive adjustments to net income		—			—			—			—

Diluted net income (loss)		$	361		$	(9	)	$	1,963		$	(2,175	)

Denominator:
Basic weighted average common shares outstanding			133,356,932			104,832,898			123,929,455			100,101,589
Effect of dilutive securities			—			—			—			—
	Options to purchase common shares		3,213,917			—			3,213,917			—
	Assumed treasury shares purchased		(1,623,441	)		—			(1,609,706	)		—
	Unvested restricted stock		—			—			—			—

Diluted weighted average commons shares outstanding			134,947,408			104,832,898			125,533,666			100,101,589

Basic net income (loss) per share			0.00			0.00			0.02			(0.02	)

Diluted net income (loss) per share			0.00			0.00			0.02			(0.02	)

For the three and nine month periods ended September 30, 2010, options to acquire 4.3 million common shares were excluded from the diluted weighted average shares outstanding because the exercise of these options would have been anti-dilutive.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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, 2010 and December 31, 2009, the Company has recorded a net asset of $931,000 and $604,000 respectively, and a related liability of $1.5 million and $1.1 million respectively.

The information below reconciles the value of the asset retirement obligation for the periods presented (in thousands):

		For the Nine Months Ended September 30, 2010			For the Year Ended December 31, 2009

Balance beginning of period		$	1,060		$	787
	Liabilities incurred		360			252
	Liabilities settled		(67	)		(74	)
	Revisions		65			—
	Accretion expense		86			95

Balance end of period		$	1,504		$	1,060

Off Balance Sheet Arrangements

Other than standard operating leases and our drilling rig commitments as described in Note 5 below, the Company did not have any other off balance sheet financing arrangements within the meaning of GAAP at September 30, 2010 and December 31, 2009.

Recently Adopted Accounting Pronouncements

In January 2010, the FASB issued Accounting Standards Update ("ASU") 2010-03,Extractive Activities—Oil and Gas (Topic 932), to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules. The significant modifications involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month average of the first day of the month prices and additional disclosure requirements. In contrast to the applicable SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. In April 2010, the FASB issued ASU 2010-14 which amends the guidance on oil and gas reporting in ASC 932.10.S99-1 by adding the Codification SEC Regulation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU 2010-14 are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments.

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

In January 2010, the FASB issued ASU 2010-06, "Improving Disclosures About Fair Value Measurements", which provides amendments to fair value disclosures. ASU 2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. The revised guidance for transfers into and out of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010, with the amendments to Level 3 disclosures effective beginning after January 1, 2011. ASU 2010-06 concerns disclosure only. Neither the current requirements nor the amendments effective in 2011 will have a material impact on the Company's financial position or results of operations.

Note 3—Wells in Progress

The following table reflects the net changes in capitalized additions to wells in progress during the nine months ended September 30, 2010 and the year ended December 31, 2009, and includes amounts that were capitalized and reclassified to producing wells in the same periods (in thousands).

	For the Nine Months Ended September 30, 2010			For the Year Ended December 31, 2009

Beginning balance	$	2,691		$	728
Additions to capital wells in progress costs pending the determination of proved reserves		20,889			16,128
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves to full cost pool		(10,304	)		(14,165	)

Ending balance	$	13,276		$	2,691

As of September 30, 2010, wells in progress included seven gross (3.8 net) Kodiak-operated, one gross (0.3 net) non-operated well in the Williston Basin and two gross (0.5 net) non-operated wells in the Green River Basin. Six of the seven Williston Basin Kodiak-operated wells classified as wells-in-progress as of September 30, 2010 are anticipated to be completed in the fourth quarter of 2010, and the remaining well is anticipated to be completed in the first quarter of 2011. The Green River Basin wells in progress were drilled in 2008 and 2009 and completion work is anticipated to continue in 2010.

Note 4—Stock-based Compensation Plan

In 2007, the Company adopted the 2007 Stock Incentive Plan (the "2007 Plan"), which replaced the Incentive Share Option Plan. The 2007 Plan authorized 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. On June 3, 2010, the shareholders of the Company approved Amendment No. 1 to the Company's 2007 Plan to increase the maximum number of shares of the Company's common stock, no par value, available for grant under the 2007 Plan from 8 million shares to 16.6 million shares through December 31, 2010. Each subsequent year, the maximum number of shares of common stock available for issuance under the 2007 Plan, as amended, will be equal to 14% of the Company's then outstanding shares of common stock.

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4—Stock-based Compensation Plan (Continued)

The Company granted stock options to acquire 2.7 million common shares at a weighted average exercise price of $3.08 per share and 1.2 million stock options at a weighted average exercise price of $1.18 per share during the nine month periods ended September 30, 2010 and September 30, 2009, respectively.

Compensation expense charged against income for all stock-based awards during the nine months ended September 30, 2010 and 2009 on a pre-tax basis was approximately $2.8 million and $2.1 million, respectively, which is included in general and administrative expense in the condensed consolidated statements of operations.

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

	For the Nine Months Ended September 30, 2010			For the Year Ended December 31, 2009

Risk free rates		0.70 - 3.02	%		1.24 - 1.34	%
Dividend yield		0	%		0	%
Expected volatility		97.21 - 102.11	%		107.01 - 108.93	%
Weighted average expected stock option life		4.42 years			2.97 years
The weighted average fair value at the date of grant for stock options granted is as follows:
Weighted average fair value per share	$	2.13		$	0.77
Total options granted		2,700,000			1,150,000
Total weighted average fair value of options granted	$	5,750,448		$	865,433

A summary of the stock options outstanding as of December 31, 2009 and September 30, 2010 is as follows:

				Weighted Average Exercise Price

Balance outstanding at January 1, 2009		7,507,499		$	2.87
	Granted	1,150,000			1.18
	Canceled	(1,946,999	)		4.65
	Expired	(775,000	)		0.45
	Exercised	(350,500	)		0.95

Balance outstanding at December 31, 2009		5,585,000		$	2.36
	Granted	2,700,000			3.08
	Canceled	(181,354	)		2.76
	Expired	—			—
	Exercised	(635,979	)		0.99

Balance outstanding at September 30, 2010		7,467,667		$	2.73

Options exercisable at September 30, 2010		4,365,333		$	2.75

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4—Stock-based Compensation Plan (Continued)

At September 30, 2010, stock options outstanding were as follows:

Exercise Price

$0.36 - $1.00	561,000	8.25
$1.01 - $2.00	1,355,917	2.95
$2.01 - $3.00	1,250,000	8.63
$3.01 - $4.00	3,795,750	4.10
$4.01 - $5.00	190,000	0.74
$5.01 - $6.26	315,000	6.65

	7,467,667	4.98

The aggregate intrinsic value of both outstanding and vested options as of September 30, 2010 was $6.3 million based on the Company's September 30, 2010 closing common stock price of $3.39 per share. The total grant date fair value of the shares vested during the nine months ended September 30, 2010 was $1.9 million. As of September 30, 2010, there was $3.6 million 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, 2010, there were 8,000 unvested shares of restricted stock with a weighted-average grant date fair value of $3.59 per share. Total unrecognized compensation cost of $19,000 related to non-vested restricted stock is expected to be recognized over a nine month period. The Company recognizes compensation cost over the requisite service period for the entire award. The fair value of restricted stock grants is based on the stock price on the grant date and the Company assumes no annual forfeiture rate.

Note 5—Commitments and Contingencies

The Company leases office facilities in Denver, Colorado and Dickinson, North Dakota under operating lease agreements that expire on June 30, 2012 and December 31, 2010, respectively. Rent expense for the Company's Denver, Colorado office was $195,000 and $186,000 for the nine month periods ended September 30, 2010 and 2009, respectively.

The following table shows the remaining annual rentals per year for the life of the Denver office space lease (in thousands):

Years ending on December 31,

2010	$	73
2011		303
2012		154

Total	$	530

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5—Commitments and Contingencies (Continued)

Purchase Agreement. For a further discussion of our obligations under the Asset Purchase Agreement, see the discussion above in Note 2.

The Company is currently subject to three drilling rig contracts. As a result of having completed the two year drilling commitment applicable to the first drilling rig, there is no associated termination fee for this rig. The Company is currently using and intends to continue operating this rig and is currently negotiating a contract extension. The second rig was placed into operation in March 2010 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior to March 10, 2012. This contract can also be extended by mutual consent. The estimated termination fee for the second rig is $4.4 million as of September 30, 2010. The Company is currently utilizing both rigs for drilling in the Williston Basin and expects to continue utilization through their respective terms. During the second quarter of 2010, the Company entered into a contract for the use of a third drilling rig. The third rig contract entails a one-year drilling commitment with variable termination fees. The estimated termination fee for this third rig is $3.8 million as of September 30, 2010. The Company currently expects to utilize this third rig in its operations in the Williston Basin.

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

Note 6—Credit Facility

On May 24, 2010, the Company, through its wholly-owned subsidiary, Kodiak USA, entered into a $200 million, four-year, revolving, senior secured credit agreement with Wells Fargo Bank, N.A. (the "Lender"). The outstanding principal balance of the revolving loan, together with all unpaid fees and expenses relating thereto, shall be due and payable no later than May 24, 2014. As of September 30, 2010, and, as of the time of this filing, the Company had no borrowing under this credit facility.

Concurrent with the credit agreement, the Company entered into a guarantee pursuant to which the Company guarantees to the Lender all of the obligations of Kodiak USA under the credit agreement and pledges a security interest in 100% of its equity interests in Kodiak USA as collateral support for its obligations under the guaranty and the obligations of Kodiak USA under the credit agreement. Additionally, Kodiak USA granted a security interest in substantially all of its assets, including mortgages on at least 80% of its interests in oil and gas properties on a discounted basis. Availability under the credit agreement is subject at all times to the then applicable borrowing base, which is recalculated with scheduled redeterminations at December 31 and June 30 of each year. The Company can request two additional redeterminations per year, thereby allowing for the ability to adjust the borrowing base up to four times in a calendar year. The borrowing base was $20 million as of September 30, 2010. Because of the Acquisition discussed below and assuming its completion and funding, in part, through this facility with its borrowing base increased as anticipated based on the commitment letter from the Lender, at closing there would be no remaining availability.

The credit agreement also makes available to the Company standby letters of credit in an amount equal to the lesser of the then applicable borrowing base or $5 million and reduces availability for loans under the credit agreement on a dollar for dollar basis. The Company had $192,000 in outstanding standby letters of credit under the credit agreement as of September 30, 2010, which is considered usage (not borrowings) for purposes of calculating availability and commitment fees. Subsequent to September 30, 2010 we have not issued any new letters of credit.

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6—Credit Facility (Continued)

Interest on the revolving loans is payable at one of the following two variable rates: the Alternate Base Rate for ABR Loans or the Adjusted LIBO Rate for Eurodollar loans, as selected by the Company, plus an additional percentage that can vary on a daily basis and is based on the daily unused portion of the facility. This additional percentage is referred to as the "Applicable Margin" and varies depending on the type of loan. The grid below shows the Applicable Margin options depending on the applicable Borrowing Base Utilization Percentage.

Borrowing Base Utilization Grid


Borrowing Base Utilization Percentage	<25.0%	³25.0% <50.0%	³50.0% <75.0%	³75.0% <90.0%	³90.0%
Eurodollar Loans	2.25%	2.50%	2.75%	3.00%	3.25%
ABR Loans	1.25%	1.50%	1.75%	2.00%	2.25%
Commitment Fee Rate	0.50%	0.50%	0.50%	0.50%	0.50%

The credit agreement contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (a) covenants to comply with a current ratio of consolidated current assets (including unused borrowing capacity) to consolidated current liabilities not less than 1.0:1.0 and a ratio of total debt to EBITDAX (as defined in the credit agreement) not greater than 3.75:1.0; (b) limitations on liens and incurrence of debt covenants; (c) limitations on dividends, distributions, redemptions and restricted payments covenants; (d) limitations on investments, loans and advances covenants; and (e) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. As of September 30, 2010, the Company was in compliance with all covenants under the credit agreement.

Note 7—Common Stock

On August 18, 2010, the Company closed a public offering of 28,750,000 shares of common stock, including the full exercise of the underwriters' over-allotment option of 3,750,000 shares. All shares were sold at a price of $2.75 per share. The net proceeds of the offering, after deducting underwriting discounts and commissions and our estimated offering expenses, were approximately $74.6 million.

Note 8—Fair Value Measurements

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

•: Level 1: Quoted prices are available in active markets for identical assets or liabilities;
•: Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 8—Fair Value Measurements (Continued)

•: Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010 by level within the fair value hierarchy (in thousands):

		Fair Value Measurements Using

		Level 1		Level 2			Level 3		Total
Liabilities:
	Commodity price risk management liability	$	—	$	(1,101	)	$	—	$	(1,101	)

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company's own credit rating. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At September 30, 2010, derivative instruments utilized by the Company consist of both "no cost" collars and swaps. The crude oil derivative markets are highly active. Although the Company's derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

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

Note 9—Differences Between Canadian and United States Accounting Principles

These financial statements have been prepared in accordance with GAAP, 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 ("Canadian GAAP"). 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.

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10—Subsequent Event

Bakken/Three Forks Properties Acquisition

As discussed above, on October 19, 2010, the Company and Kodiak USA entered into the Asset Purchase Agreement to acquire approximately 14, 500 net acres of Bakken/Three Forks leasehold and related producing properties in the Williston Basin of North Dakota. The aggregate purchase price is expected to be comprised of $99 million in cash and 2.75 million shares of the Company's common stock. In the event certain conditions precedent to the issuance of such shares are not satisfied, Kodiak USA will be obligated to pay $11 million in cash in lieu of the Company issuing such shares. The closing of the acquisition is expected to occur in November 2010.

In the event the Company issues the 2.75 million new shares of common stock upon closing, as is currently expected, the Company will value the stock on the closing date for the purposes of determining the purchase price in accordance with ASC 805. The value of such consideration shares will fluctuate based upon changes in the price of shares of the Company's common stock at the closing date. The Company's common stock was priced at $3.81 per share on October 19, 2010, the date of entering into the Acquisition. At closing, a change in the Company's share price of plus/minus 10% from the share price of $3.81 at the date of signing the Asset Purchase Agreement ($3.43-$4.19) will result in an increase/decrease in the total consideration of $1.05 million.

For purposes of the following preliminary purchase price allocation, the value of the common shares to be issued was determined based on the closing price of the Company's common stock on the NYSE Amex LLC at November 2, 2010 ($4.35 per share), the most recent date available for this filing. The purchase price allocation is preliminary and includes significant use of estimates. This preliminary allocation is based on information that was available to management at the time these financial statements were prepared. Management has not yet had the opportunity to complete its assessment of the fair values of the assets acquired and liabilities assumed. Accordingly, the allocation will change as additional information becomes available and is assessed by the Company, and the impact of such changes may be material.

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10—Subsequent Event (Continued)

The following table summarizes the purchase price and the preliminary estimated values of assets acquired and liabilities assumed (in thousands, except share data):

		November 2, 2010

Purchase Price
Consideration Given:
Cash		$	99,000
Kodiak Oil & Gas Corp. common stock (2,750,000 shares)		$	11,963
	Total consideration given:	$	110,963

Preliminary Allocation of Purchase Price
Assets & Liabilities Acquired:
Proved oil and gas properties		$	40,052
Unproved oil and gas properties		$	70,983

	Total assets acquired	$	111,035
Asset retirement obligation		$	72

	Total liabilities acquired	$	72
Net assets acquired		$	110,963

Internal Revenue Code ("IRC") Section 382 addresses company ownership changes and provides for the calculation of a limitation regarding the amount of certain deductions and other tax attributes that can be claimed on an annual basis following an ownership change. The Company has not yet determined whether the acquisition of the Properties will result in an IRC Section 382 limitation. However, the Company does not expect the application of IRC Section 382 to cause the Company to have a current federal tax liability for the period ending December 31, 2010.

The following pro forma results of operations are provided for the nine-month periods ended September 30, 2010 and September 30, 2009, as though the Acquisition had been completed as of January 1, 2009. The following supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined businesses for the periods presented or that may be achieved by the combination in the future. Future results may vary significantly from the results reflected in the following pro forma financial information because of future events and transactions, as well as other factors (in thousands, except share data).

		Nine Months Ended

		September 30, 2010			September 30, 2009
Revenues		$	23,719		$	6,587
Net income (loss)		$	(443	)	$	(7,585	)
Pro forma income (loss) per common share:
	Basic	$	0.00		$	(0.07	)
	Diluted	$	0.00		$	(0.07	)

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10—Subsequent Event (Continued)

The pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of the properties to be acquired pursuant to the Acquisition, by reflecting certain reclassifications to conform presentation of such properties to the Company's accounting policies and by reflecting the impact of the preliminary purchase price allocation discussed above. The pro forma results of operations do not include any cost savings or other synergies that may result from the Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties to be acquired.

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

Forward-Looking Statements

The information discussed in this Quarterly Report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could," and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

•: future capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;
•: unsuccessful drilling and completion activities and the possibility of resulting write-downs;
•: a decline in oil or natural gas production or oil or natural gas prices and the impact of general economic conditions on the demand for oil and natural gas and the availability of capital;
•: our ability to close the Acquisition;
•: geographical concentration of our operations;
•: ongoing U.S. and global economic uncertainty;
•: constraints imposed on our business and operations by our credit facility and our ability to generate sufficient cash flows to repay our debt obligations;
•: availability of borrowings under our credit facility;
•: termination fees related to drilling rig contracts;
•: increases in the cost of drilling, completion and gas gathering or other costs of production and operations;
•: financial losses and reduced earnings related to our commodity derivative agreements, and failure to produce enough oil to satisfy our commodity derivative agreements;
•: historical incurrence of losses;
•: adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;
•: hazardous, risky drilling operations and adverse weather and environmental conditions;
•: limited control over non-operated properties, and reliance on third party service providers over whom we have limited control;
•: reliance on limited number of customers and creditworthy of our customers;
•: title defects to our properties and inability to retain our leases;

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•: incorrect estimates of our proved reserves, and the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;
•: our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped operated and non-operated acreage positions;
•: our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;
•: increases in interest rates;
•: our ability to retain key members of our senior management and key technical employees, and conflicts of interests with respect to our directors;
•: marketing and transportation constraints in the Williston Basin;
•: risks associated with prior business activities;
•: effects of competition;
•: federal and tribal regulations and laws;
•: our level of indebtedness;
•: risks in connection with potential acquisitions and the integration of significant acquisitions;
•: price volatility of oil and natural gas prices;
•: impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;
•: effect of seasonal factors;
•: lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oil field services;
•: further sales or issuances of common stock; and
•: our common stock's limited trading history.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in our filings with the SEC and in Part II, Item 1A of this Quarterly Report. For additional information regarding risks and uncertainties, please read our filings with the SEC under the Exchange Act and the Securities Act, including our Annual Report on Form 10-K for the fiscal year ended December 31, 2009 and our Quarterly Report on Form 10-Q for the fiscal year ended June 30, 2010. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this Quarterly Report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

Overview

Kodiak is an independent energy company focused on the exploration, exploitation, acquisition and production of crude oil and natural gas in the United States. Our oil and natural gas reserves and operations are primarily concentrated in two Rocky Mountain basins, the Williston Basin of North Dakota and Montana and the Green River Basin of Wyoming and Colorado. Kodiak's corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development

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and exploratory drilling opportunities on high potential conventional and non-conventional oil and natural gas prospects that we have the opportunity to explore, drill and develop.

Recent Developments

Public Offering

Asset Purchase Agreement

On October 19, 2010, we and our wholly-owned subsidiary, Kodiak USA, entered into the Asset Purchase Agreement with a private oil and gas company ("Seller"), under which Kodiak USA agreed to, among other things, acquire from Seller certain oil and gas properties located in the State of North Dakota, and various other related permits, contracts, equipment, data and other assets (the "Acquisition"). The aggregate purchase price is expected to be comprised of $99 million payable in cash by Kodiak USA and 2.75 million shares of our common stock (the "Acquisition Consideration Shares"). In the event we fail to satisfy certain conditions precedent to the issuance of the Acquisition Consideration Shares, Kodiak USA will be obligated to pay $11 million in cash to Seller in lieu of us issuing the Acquisition Consideration Shares. The closing of the Acquisition is currently expected to take place on November 18, 2010, subject to satisfaction of various closing conditions.

Pursuant to the Asset Purchase Agreement, Kodiak USA has deposited $5.5 million into escrow that will be credited to the purchase price on the completion of the Acquisition. If the Asset Purchase Agreement is terminated, the escrow deposit will be returned to Kodiak USA, except in the case of a material breach of the Asset Purchase Agreement by Kodiak USA, in which event the escrow deposit will be retained by Seller.

Upon completion of the transaction, Kodiak would acquire 19,016 gross mineral acres (11,742 net) in McKenzie County, North Dakota. Additionally, Kodiak will acquire 4,117 gross (2,752 net) mineral acres in northern Williams County and southern Divide County, North Dakota. The McKenzie County acreage includes four producing well bores and associated equipment, three of which will be operated by Kodiak at closing. As of October 2010, the four wells produced approximately 500 net barrels of oil equivalent (BOE) per day. Kodiak will operate the majority of the leasehold to be acquired. In McKenzie County, the Company will own an approximate 87% working interest (WI) and a 70% net revenue interest (NRI). In the Williams and Divide lands, Kodiak will own 100% WI and 82% NRI.

Liquidity and Capital Resources

2010 Capital Resources and Expenditures

Excluding the effect of the Acquisition, we are maintaining our previously announced 2010 capital expenditure budget of $75 million. This capital expenditure budget remains subject to modification, both as to amount and allocation, and is subject to variation due to such factors as our drilling results, availability and cost of oil field services and equipment and expected commodity prices, as well as available working capital. Through September 30, 2010, we had invested $52.6 million in total capital expenditures.

The required cash outlay necessary to close the Acquisition is expected to be $99 million. However, as discussed above, in the event that certain conditions are not timely satisfied by us, Kodiak USA will be obligated to pay an additional cash amount of $11 million in lieu of us issuing the Acquisition Consideration Shares. Our total capital expenditures for 2010 are therefore expected to

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range from $175 million to $186 million, of which up to $133 million is estimated to be spent in the fourth quarter of 2010, assuming no shares are issued in the acquisition. We expect to fund such remaining 2010 capital expenditure budget through a combination of the following sources of capital:

•: New term debt: We are in advanced discussions to establish a senior secured second lien term loan with a total commitment of $40 million, all of which we would apply toward our remaining 2010 capital expenditures. We have a commitment letter for this facility but standard conditions and requirements must be satisfied before closing, and there can be no assurances as to the availability of these funds.
•: Expanded revolving debt: We are in advanced discussions to expand our existing revolving borrowing base from $20 million to $50 million as a result of our drilling and completion activities and, to a lesser extent, due to the oil and gas reserves included in the Acquisition. As of September 30, 2010, there were no outstanding borrowings under this facility. Although we have a commitment letter from the lender to increase the facility, certain conditions and requirements must be met before closing, and there can be no assurances as to the availability of these funds.
•: Working capital on-hand and anticipated cash flow from operations. We expect to fund the balance of the 2010 capital expenditure budget not covered through the proposed new term debt and expanded revolving debt through existing working capital and expected cash flow from operations. As of September 30, 2010, our working capital totaled $61 million.

2011 Outlook

Looking forward to 2011, we anticipate our participation in as many as five gross rigs by mid-year 2011. In addition to our two current operated rigs, we have contracted for delivery of a third rig expected in the first quarter of 2011. Furthermore, our partner in an area of mutual interest covering a portion of our acreage has indicated they will be mobilizing one rig in the fourth quarter of 2010 followed by a second rig in mid-year 2011, which will give rise to additional capital expenditure commitments on our part. While we do not know the drilling program for the rigs operated by our joint venture partner, we anticipate having a working interest of up to 50% in most of the wells to be potentially drilled by these two non-operated rigs. A two-well pad location has been built for the first two wells and we anticipate additional permits and locations to follow.

We anticipate funding this 2011 capital program through a combination of the increase in our operating cash flows, working capital, including prepaid drilling costs and tubular inventory, and additional credit available under either our borrowing base or second lien term loan facilities. We anticipate that our operating cash flows will continue to increase as additional wells are drilled and placed on production. For the third quarter of 2010, our average sales volumes were 1,378 BOE per day, an increase of 83% over the same period in 2009. Although these sales volumes do not include natural gas that is currently being flared, third-party pipelines are currently installing infrastructure for

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gas gathering and processing. We expect the incremental gas and natural gas liquids sales to begin in the fourth quarter of 2010 with most of the flared gas captured by early 2011.

Currently, we have six gross (3.4 net) wells that have been drilled and are awaiting completion, and we expect to have a seventh (.95 net) well drilled and awaiting completion before year-end. We are installing surface facilities and have scheduled completion dates in November and December 2010 for up to six of these wells. Provided that we are able to complete the six gross (3.9 net) wells in the fourth quarter of 2010 and that these wells produce at rates we have experienced in existing wells, our production rates will grow significantly. Concurrently, we expect that our borrowing base will increase with the addition of proved properties as a result of these completion activities. However, we cannot give assurance that either our cash flow from operations or increases in our borrowing base will be sufficient to fund our anticipated capital expenditures (SeeRisk Factors).

Capital Resources for the Periods Ended September 30, 2010 and 2009

The following table sets forth the balances and changes in our capital resources as of and for the three and nine month periods ended September 30, 2010 and 2009, excluding availability under our credit facility (in thousands):

	For the three months ended September 30,						For the nine months ended September 30,

	2010			2009			2010			2009
Cash and cash equivalents at end of the period	$	61,827		$	1,755		$	61,827		$	1,755
Net cash provided by operating activities	$	7,964		$	5,752		$	12,819		$	5,058
Net cash used in investing activities	$	(20,232	)	$	(8,045	)	$	(50,687	)	$	(18,203	)
Net cash provided by financing activities	$	69,714		$	225		$	74,809		$	7,318
Net cash flow	$	57,446		$	(2,068	)	$	36,941		$	(5,827	)

Kodiak ended September 30, 2010 with total working capital of approximately $60.8 million (including cash and cash equivalents of $61.8 million), as compared to working capital of approximately $28.3 million at year-end 2009 (including cash and cash equivalents of $24.9 million). From time to time, an important component of our working capital is our inventory, prepaid expenses and other current assets. As operator of most of our operations in the Williston Basin, we must place orders and take delivery of tubular goods and other oil field equipment in advance of actual drilling in order to assure availability of these supplies. As wells are drilled, these become part of our cost of wells, whereby our working interest share is already paid while the portion related to other working interest partners is recovered through our joint interest billings. As of September 30, 2010, we had prepaid $18.2 million towards the cost of tubular goods, compared to $7.3 million at December 31, 2009.

Our operating cash flows are significantly affected by the success of our drilling and completion activity, oil and natural gas commodity prices and the costs related to operating our properties. In the nine months ended September 30, 2010, our oil and natural gas revenue increased by approximately 207% to $20 million from $6.5 million for the nine months ended September 30, 2009. This increase is largely the result of the increase in our crude oil production in 2010 compared to 2009, together with improved prices realized for our oil and natural gas production. The increase in revenue was partially offset by increased total costs and expenses of $16.9 million for the nine months ended September 30, 2010 from $8.7 million for same period of 2009. Both the increase in revenue and expenses are primarily due our growing inventory of producing wells at September 30, 2010 as compared to September 30, 2009.

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During the first nine months of 2010, we drilled or participated in 16 gross wells (7.3 net) and completed 12 gross wells (4.7 net). In total, we anticipate drilling or participating in 21 gross wells (10.7 net) and completing 18 gross wells (8.6 net) during 2010. All of these wells are in our Williston Basin operating area. We incurred capital expenditures of approximately $53 million during this period. The table below sets forth our capital expenditures for the nine months ended September 30, 2010, and our current budgeted capital expenditures for 2010 for our principal properties. Net capital expenditures include both cash expenditures and accrued expenditures and are net of proceeds from divestitures.

Project Location	2010 Net Capital Expenditures(1) ($000)		Revised 2010 Budgeted Net Capital Expenditures ($000)

Williston Basin
Mission Canyon/Red River wells and related infrastructure		3,300		1,300
Bakken wells and related infrastructure		36,700		60,000
Acreage/Seismic		12,350		13,350

Total Williston Basin	$	52,350	$	74,650

Wyoming	$	250	$	350

Total All Areas	$	52,600	$	75,000

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

Properties

Williston Basin

Our primary geologic targets in the Williston Basin are the Bakken and Three Forks Formations. The Williston Basin also produces from many other formations including, but not limited to, the Mission Canyon, Nisku and Red River. We are currently operating a two-rig program in the Williston Basin and anticipate continued operation throughout 2010 with these rigs. These two rigs are under two-year contracts that expire in the fourth quarter of 2010 and the first quarter of 2012, respectively. In the second quarter of 2010, we contracted for a third drilling rig and anticipate taking delivery of the rig in the first quarter of 2011. In addition to our operated rigs, we have been informed by our joint venture partner on our Dunn County acreage that they will be mobilizing a drilling rig later this year on the lands they operate with the expectation to add a second rig during the first part of 2011. The initial two well drilling pad has been constructed and we expect drilling to commence in the near term. While we do not know the drilling program for the rigs operated by our joint venture partner, we anticipate having a working interest of up to 50% in most of the wells to be potentially drilled by these two non-operated rigs.

In the nine months ended September 30, 2010, the Company's capital expenditures in the Williston Basin totaled $52 million, including $40 million for drilling, completion and infrastructure activities and $12 million for acreage leasing. During the first 10 months of 2010 Kodiak has acquired 8,960 net acres for total consideration of $14.7 million or an average purchase price of $1,638 per acre. For the entire year of 2010, our current capital expenditure budget for the Williston Basin includes $75 million for drilling, completion, related infrastructure and acreage leasing.

Bakken/Three Forks Acquisition

On October 19, 2010, we announced that Kodiak had entered into the Asset Purchase Agreement with a private oil and gas company to acquire high-working-interest, contiguous Bakken/Three Forks

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Williston Basin leasehold and producing properties. Upon completion of the transaction, Kodiak would acquire 19,016 gross mineral acres (11,742 net) in McKenzie County, North Dakota. Additionally, Kodiak will acquire 4,117 gross (2,752 net) mineral acres in northern Williams County and southern Divide County, North Dakota. The McKenzie County acreage includes four producing well bores and associated equipment, three of which will be operated by Kodiak at closing. As of October 2010, the four wells produced approximately 500 net barrels of oil equivalent (BOE) per day. Kodiak will operate the majority of the leasehold to be acquired. In McKenzie County, the Company will own an approximate 87% working interest (WI) and a 70% net revenue interest (NRI). In the Williams and Divide lands, Kodiak will own 100% WI and 82% NRI.

Bakken/Three Forks Development: Dunn County, N.D. (55,775 gross and 34,635 net acres)

As of October 31, 2010, the Company has four wells in Dunn County awaiting completion. The Two Shields Butte (TSB) four-well pad consists of the TSB #14-21-4H Bakken well, the TSB #14-21-33-16H3 Three Forks well, the TSB #14-21-33-15H and the TSB #14-21-16-2H Bakken wells. Fracture stimulation dates have been scheduled for mid-November and continuing into December of 2010, subject to weather conditions and availability of equipment.

The first well the Company intends to complete is the TSB #14-21-33-16H3, that was drilled to test the productive potential of the Three Forks Formation. Kodiak expects that fracture stimulation work on the remaining three wells on this pad will continue into December, with the final well being completed by year end. The well bores have been drilled to evaluate the effectiveness of reservoir drainage and communication with four well bores in the Bakken Formation within a drilling unit. Furthermore the Three Forks test will provide information on the communication between the Three Forks and Bakken and will help determine spacing of future Three Forks well bores.

The Company is currently drilling the TSB #2-24-12-2H Bakken well as the first well on a new four-well pad.

McKenzie County, N.D. (20,672 gross and 13,294 net acres)

In the Grizzly project area, located in the Mondak Field of the southeastern Elm Coulee trend, the Grizzly #13-6H was re-entered during September 2010 and is scheduled for completion in the first quarter of 2011.

The Grizzly Federal #1-27H-R well was recently completed in 10 stages. The horizontal wellbore landed in the Three Forks Formation rather than in the intended Middle Bakken Formation. Instead of plugging back and redrilling the well, it was determined that we would evaluate the potential of the Three Forks Formation. The well tested 447 barrels of oil and 362,000 cubic feet of gas or 507 barrels of oil equivalent on a 32/64^ths inch choke with 90 PSI flowing tube pressure during the initial 24 hour test period. The well does help prove up the potential of the Three Forks Formation in this area.

Drilling operations have recently completed on the Koala #9-5-6-5H Bakken well. The second well on this two-well pad, the Koala #9-5-6-12H3 Three Forks well, is currently drilling.

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The following summary provides a tabular presentation of data pertinent to Kodiak's Middle Bakken and Three Forks drilling and completion activities during 2010 (gas is converted on a 6 Mcf to 1 barrel of oil basis):

Kodiak Oil & Gas Corp. N.D. (Bakken) Drilling and Completion Activities
Longer Laterals (8,000' to 10,000')—Dunn County, N.D.

							Production

					IP 24- Hour Test BOE/D		Production						Gas / Oil Ratio (GOR) Range
Well	WI / NRI (%)		Completion Date		IP 24- Hour Test BOE/D		30 Day Cum BOE/D		60 Day Cum BOE/D		90 Day Cum BOE/D		Gas / Oil Ratio (GOR) Range		Status
MC #13-34-28-1H		59 /48		9/14/2010		1,906		1,082		1,074		—		700	Flowing Well
TSB #14-21-33-16H3		50 /41		Q410		—		—		—		—		—	Waiting completion
TSB #14-21-33-15H		50 /41		Q410		—		—		—		—		—	Waiting completion
TSB #14-21-16-2H		50 /41		Q410		—		—		—		—		—	Waiting completion
TSB #2-24-12-2H		50 /41		Q211		—		—		—		—		—	Drilling
Shorter Laterals (4,000' to 7,000')—Dunn County, N.D.
MC #16-3-11H		60 /49		2/12/2010		1,419		798		694		621		800	Flowing well
MC #16-3H		60 /49		3/2/2010		1,495		671		537		478		800	Flowing well
MC #13-34-3H		60 /49		6/7/2010		1,517		666		569		484		700	Flowing well
MC #13-34-28-2H		59 /48		8/2/2010		2,055		1,259		1,073		—		800	Flowing well
TSB #14-21-4H		50 /41		Q410		—		—		—		—		—	Waiting completion
McKenzie County, N.D.
Grizzly 13-6H		68 / 56		Q111		—		—		—		—		—	Waiting completion
Grizzly 1-27H-R		74 / 60		9/28/2010		507		—		—		—		—	Flowing well
Koala 9-5-6-5H		95 / 78		Q410		—		—		—		—		—	Waiting completion
Koala 9-5-6-12H3		95 / 78		Q410		—		—		—		—		—	Drilling

Midstream Activities: Oil, Gas and Water Disposal Pipelines and Water Intake Facilities

In late June 2010, the Company reached a definitive agreement with a third-party pipeline operator that allows for the gathering and sales of crude oil and natural gas and gathering and disposal of water through pipelines over certain of the Company's Dunn County gross acreage position. The Company's joint venture partner in this area that operates a portion of Kodiak's leasehold had previously reached an agreement with the same pipeline operator. Combined, these agreements allow all of the wells completed by either company within the area of mutual interest to produce into the same gathering and pipeline system.

The gathering system has been completed through the northern part of Kodiak's Dunn County leasehold. Construction work has been commenced to connect the first four of the Company's currently producing wells. Moving oil and gas quantities through the pipeline system eliminates trucking costs and associated surface disturbance and mitigates weather-related production interruptions. Additionally, Kodiak can capture revenue generated from the sales of its associated natural gas and natural gas liquids that are currently flared. The pipeline agreement also includes water gathering and disposal which can further reduce lease operating expense while minimizing surface disturbance by eliminating the trucking of water.

Green River Basin (48,000 gross and 15,000 net acres)

The operator of the Vermillion Basin prospect has re-entered a well that was vertically drilled in 2008 to the top of the Baxter Shale and has horizontally drilled a lateral to evaluate the potential of the Baxter Shale interval. The well is currently waiting on completion.

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Production, Average Sales Prices and Production Costs

Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. Commodity prices are beyond our control and are difficult to predict. Market prices reflect worldwide concerns regarding economic conditions and demand for petroleum products, amid a host of uncertainties caused by political instability, fluctuations in the U.S. dollar and crude oil refining constraint. We partially mitigate this risk through the use of commodity derivatives as further discussed in Item 3, below. We receive lower prices for our oil and gas than what is posted on the New York Mercantile Exchange ("NYMEX") and these price differentials received for our products vary from month to month.

The Company's oil and gas sales volumes are directly related to the results of its exploratory and acquisition activities. Production volumes may vary monthly as various wells are completed or maintained in an effort to provide optimal production. Sales volumes, prices received and production costs are summarized in the following table for the three and nine month periods ended September 30, 2010 and September 30, 2009.

	For the three months ended				For the nine months ended

	September 30, 2010		September 30, 2009		September 30, 2010		September 30, 2009
Sales Volume (Bakken only):
Gas (Mcf)		1,458		1,453		5,342		4,817
Oil (Bbls)		111,518		52,825		263,638		81,691
Production volumes (BOE)		111,761		53,067		264,528		82,494
Sales Volume (Total):
Gas (Mcf)		37,342		47,982		131,224		206,554
Oil (Bbls)		120,544		61,121		284,952		112,921
Production volumes (BOE)		126,767		69,118		306,823		147,347
Price:
Gas ($/Mcf)	$	4.47	$	2.70	$	4.56	$	2.62
Oil ($/Bbls)	$	66.07	$	58.94	$	67.99	$	52.77
Production costs ($/BOE):
Lease operating expenses	$	6.25	$	3.80	$	6.72	$	3.44
Production and property taxes	$	7.05	$	6.69	$	7.44	$	4.45
Gathering, transportation, marketing	$	0.16	$	0.21	$	0.29	$	0.46

Results of Operations

For the Three Months Ended September 30, 2010 compared to the Three Months Ended September 30, 2009

The Company reported net income for the three months ended September 30, 2010 of approximately $361,000 compared to a net loss of $9,000 for the same period in 2009. A non-cash charge of $1.1 million was included in the net income for the 2010 period for the change in the fair value of commodity derivatives that we use to mitigate our exposure to crude oil price volatility. There was no gain or loss for such risk management activities for the comparable 2009 period. The improvement from a net loss to net income is attributable to the new production from our Bakken wells, which includes sales from two recently completed Bakken wells which came on to production in the third quarter of 2010. Our volumes on a BOE basis increased 83% from 69,118 BOE in the third quarter of 2009 to 126,768 BOE during the third quarter of 2010. In addition, we realized increased prices for both oil and natural gas during the three month period ended September 30, 2010 versus the

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three month period ended September 30, 2009. Oil price realizations increased by 12% to $66.07 per barrel for the three month period ended September 30, 2010, compared to $58.94 per barrel for the same period in 2009. Total natural gas price realizations increased 66% to $4.47 per Mcf for the three month period ended September 30, 2010, compared to $2.70 per Mcf for the same period in 2009. Our increased oil production and, to a lesser extent, the increased pricing received for our products, for the period resulted in an increase in oil and gas revenue of $4.4 million, from approximately $3.7 million for the three-month period ended September 30, 2009 to $8.1 million for the same period in 2010, a 118% increase.

The following table sets forth of the Company's financial results, capital resources and liquidity as of and for the three months ended September 30, 2010 as compared to the three months ended September 30, 2009 (in thousands).

	For the three months ended

	September 30, 2010			September 30, 2009
Financial Results
Total revenue	$	6,994		$	3,739
Total costs and expenses	$	6,569		$	3,748
Net income (loss)	$	361		$	(9	)
Basic net income (loss) per common share	$	—		$	—
Capital Resources and Liquidity
Cash and cash equivalents at end of the period	$	61,827		$	1,755
Net cash provided by operating activities	$	7,964		$	5,752
Cash used in investing activities in oil and gas properties, net of divestitures	$	(20,397	)	$	(6,120	)

Oil and Gas Revenue and Production

During the three month period ended September 30, 2010, as compared to the same period in 2009, crude oil production volumes increased 97% due to new production from completion operations on our Dunn County, North Dakota operating area. Natural gas production volumes decreased 22% due to our decision to limit production on our Wyoming wells and declines in other gas well production. Oil and natural gas revenues increased by $4.4 million, or 118%, compared to the third quarter of 2009, primarily due to our increased volumes attributable to our recent well completions and, to a lesser extent, increased realized pricing for oil and natural gas in 2010 versus 2009. The increase in oil and gas revenue was 88% attributable to the increase in production volumes and 12% attributable to the increase in realized commodity prices.

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of approximately $1.7 million during the three month period ended September 30, 2010, as compared to approximately $740,000 during the same period in 2009. The increase is due to our increased lease operating expenses on the fifteen new wells in production as of September 30, 2010 that were not in production in 2009 and the related severance taxes paid related to the revenue received on the new wells production. A significant portion of the operating expense is related to the disposal of water in the early months of a well's production. Since a majority of the water is related to completion operations and is largely diminished after two to three months, the well's operating expenses decline over its early production period. Overall, we have continued to bring new wells online and, as a result of the water disposal costs, our total operating expenses reflect the added cost of water disposal.

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Depletion, Depreciation and Amortization

Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was approximately $2.1 million for the three month period ended September 30, 2010, compared to $1.1 million for the same period in 2009. DD&A expense increased during the quarter due to increased production for the new wells placed in service from the second quarter of 2009 through the third quarter of 2010.

Ceiling Test Impairment

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower of unproved properties that are subject to amortization. For the three months ended September 30, 2010 and September 30, 2009, respectively, no impairment charges were recorded.

General and Administrative Expense

The Company's general and administrative costs were approximately $2.8 million for the three months ended September 30, 2010 compared to approximately $2.0 million for the same period in 2009. This 42% increase for the period is primarily due to adding additional employees in 2010 as the Company has increased its operational activities in the Williston Basin. We currently have 30 employees as compared to 16 at the end of 2009. Further, as we have grown our production base in the Williston Basin, we have established a regional office in Dickinson, North Dakota, that is staffed by permanent field employees that directly oversee our ongoing activities.

For the Nine Months Ended September 30, 2010 compared to the Nine Months Ended September 30, 2009

The Company reported net income for the nine months ended September 30, 2010 of approximately $2.0 million compared to a net loss of $2.2 million for the same period in 2009. A non-cash charge of $1.1 million was included in the net income for the 2010 period for the change in the fair value of commodity derivatives that we use to mitigate our exposure to crude oil price volatility. There was no gain or loss for such risk management activities for the comparable 2009 period. The improvement from a net loss to net income is attributable to the new production from our Dunn Country, North Dakota Bakken wells, where our first wells began producing in the second quarter of 2009, and includes sales from three Bakken wells which came on to production during 2010. For the nine months ending September 30, 2010, our volumes on a BOE basis increased 108% from 147,347 BOE in the nine months of 2009 to 306,823 BOE during the nine months of 2010. In addition, we realized increased prices for both oil and natural gas during the nine month period ended September 30, 2010 versus the nine month period ended September 30, 2009. Oil price realizations increased by 29% to $67.99 per barrel for the nine month period ended September 30, 2010, compared to $52.77 per barrel for the same period in 2009. Total natural gas price realizations increased 74% to $4.56 per Mcf for the nine month period ended September 30, 2010, compared to $2.62 per Mcf for the same period in 2009. Our increased oil production and, to a lesser extent, the increased pricing received for our products for the period resulted in an increase in oil and gas revenue of $13.5 million, from approximately $6.5 million to $20.0 million, a 207% increase in revenue for the nine month period ended September 30, 2010 compared to the same period.

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The following table sets forth the Company's financial results, capital resources and liquidity as of the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009 (in thousands).

	For the nine months ended

	September 30, 2010			September 30, 2009
Financial Results
Total revenue	$	18,900		$	6,544
Total costs and expenses	$	16,858		$	8,719
Net income (loss)	$	1,963		$	(2,175	)
Basic and diluted net income (loss) per common share	$	0.02		$	(0.02	)
Capital Resources and Liquidity
Cash and cash equivalents at end of the period	$	61,827		$	1,755
Net cash provided by operating activities	$	12,819		$	5,058
Cash used in investing activities in oil and gas properties, net of divestitures	$	(45,453	)	$	(15,528	)

Oil and Gas Revenue and Production

During the nine month period ended September 30, 2010, as compared to the same period in 2009, crude oil production volumes increased 152% due to new production from completion operations on our Dunn County, North Dakota operating area. Natural gas production volumes decreased 37% due to our decision to limit production on our Wyoming wells and natural declines in other gas well production. Oil and natural gas revenues increased by $13.5 million, or 207%, for the nine months of 2010 compared to the nine months of 2009, primarily due to our increased volumes attributable to our recent well completions and, to a lesser extent, increased realized pricing for oil and natural gas in 2010 versus 2009. The increase in oil and gas revenue was 84% attributable to the increase in production volumes and 16% attributable to the increase in realized commodity prices.

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of approximately $4.4 million during the nine month period ended September 30, 2010, as compared to $1.2 million during the same period in 2009. The increase is due to our increased lease operating expenses on the fifteen new wells in production as of September 30, 2010 that were not in production in 2009 and the related severance taxes paid related to the revenue received on the new wells production. A significant portion of the operating expense is related to the disposal of water in the early months of a well's production. Since a majority of the water is related to completion operations and is largely diminished after two to three months, the well's operating expenses decline over its early production period. Overall, we have continued to bring new wells online and as a result of the water disposal costs our operating expenses reflect this added cost.

Depletion, Depreciation and Amortization

DD&A was approximately $4.9 million, for the nine month period ended September 30, 2010, compared to $1.9 million for the same period in 2009. DD&A expense increased during the quarter due to increased production for the new wells placed in service from the second quarter of 2009 through the third quarter of 2010.

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Ceiling Test Impairment

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower of unproved properties that are subject to amortization. For the nine months ended September 30, 2010, and September 30, 2009, respectively, no impairment charges were recorded.

General and Administrative Expense

The Company's general and administrative costs were approximately $7.5 million for the nine months ended September 30, 2010 compared to approximately $5.5 million for the same period in 2009. This 35% increase for the period is primarily due to adding additional employees in 2010 as the Company has increased its operational activities in the Williston Basin. We currently have 30 employees as compared to 16 at the end of 2009. Further, as we have grown our production base in the Williston Basin, we have established a regional office in Dickinson, North Dakota that is staffed by permanent field employees that directly oversee our ongoing activities.

Oil and Gas Leasehold

As of September 30, 2010, we had several hundred lease agreements representing approximately 148,000 gross and 81,000 net acres, primarily in the Green River Basin and Williston Basin.

As of September 30, 2010, we had an interest in approximately 56,000 gross acres and 35,000 net acres in the Bakken oil play located on the Fort Berthold Indian Reservation in Mountrail and Dunn Counties, North Dakota. The majority of our lands in this area are administered by the Bureau of Indian Affairs on behalf of the individual members of the Three Affiliated Tribes of the Fort Berthold Indian Reservation. Typically, these lands are acquired through a private negotiation with the individual land owners or the Three Affiliated Tribes and have a primary lease term of five years. The land owner typically retains an 18% landowner royalty. In most cases, these lands require an annual delay rental of $2.50 per net acre.

As of September 30, 2010, we owned an interest in approximately 33,000 gross (21,000 net) acres in the Williston Basin outside the Fort Berthold Indian Reservation in Sheridan County, Montana, and McKenzie and Divide Counties, North Dakota. This acreage is prospective for Mission Canyon, Red River, Bakken and Three Forks formations.

Our leasehold interests in the Vermillion Basin total approximately 41,000 gross and 8,800 net acres as of September 30, 2010.

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The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of September 30, 2010.

	Undeveloped Acreage(1)				Developed Acreage(2)				Total Acreage

	Gross		Net		Gross		Net		Gross		Net
Green River Basin
Wyoming		39,008		9,187		1,520		908		40,528		10,095
Colorado		7,339		4,960		0		0		7,339		4,960
Williston Basin
Montana		10,757		7,438		1,440		646		12,197		8,084
North Dakota		64,767		42,500		11,680		5,429		76,447		47,929
Other Basins
Wyoming		11,668		9,982		0		0		11,668		9,982
Acreage Totals		133,539		74,067		14,640		6,983		148,179		81,050

(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.

On October 19, 2010, we announced entering into a definitive agreement to acquire approximately 23,100 gross and 14,500 net acres of Bakken/Three Forks leasehold and related producing properties in the Williston Basin of North Dakota. The acquisition is expected to include approximately 3,000 net developed acres and 11,500 net undeveloped acres.

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

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

		Expiring Acreage

Year Ending		Gross		Net
December 31, 2010			7,951		3,833
December 31, 2011			8,889		5,895
December 31, 2012			32,616		20,083
December 31, 2013			14,656		10,001

	Total		64,112		39,812

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

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Commitments and Contingencies

Kodiak USA is obligated under the Asset Purchase Agreement for a cash amount of up to $110 million. In the event Kodiak USA fails to close the Acquisition as a result of its material breach, Kodiak USA will forfeit the $5.5 million deposit that it placed into escrow in connection with the Asset Purchase Agreement. For a further discussion of our obligations under the Asset Purchase Agreement, see the discussion above under the headings "Recent Developments" and "Liquidity and Capital Resources—2010 Capital Resources and Expenditures".

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

Off Balance Sheet Arrangements

The Company did not have any off balance sheet arrangements, as such term is defined in Item 303(a)(4)(ii) of Regulation S-K, at September 30, 2010 and December 31, 2009.

Critical Accounting Policies and Estimates

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

Recently Issued Accounting Pronouncements

In January 2010, the FASB issued Accounting Standards Update ("ASU") 2010-03,Extractive Activities—Oil and Gas (Topic 932), to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month average of the first day of the month prices and additional disclosure requirements. In contrast to the applicable SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. In April 2010, the FASB issued ASU 2010-14 which amends the guidance on oil and gas reporting in ASC 932.10.S99-1 by adding the Codification SEC Regulation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU 2010-14 are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments.

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well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010, with the amendments to Level 3 disclosures effective beginning after January 1, 2011. ASU 2010-06 concerns disclosure only. Neither the current requirements nor the amendments effective in 2011 will have a material impact on the Company's financial position or results of operations.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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 would have resulted in an approximate $37,000 change in our gross gas production revenue based on our production volumes for the three months ended September 30, 2010. A $1.00 per barrel change in the market price of oil would have resulted in an approximate $121,000 change in our gross oil production revenue based on our production volumes for the three months ended September 30, 2010.

We manage this commodity price risk exposure through the use of derivative financial instruments entered into with third-party counterparties. Currently, we utilize swaps or "no premium" collars to reduce the effect of price changes on a portion of our future oil production. A collar requires us to pay the counterparty if the market price is above the ceiling price and requires the counterparty to pay us if the market price is below the floor price. A swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's wholly-owned subsidiary, Kodiak USA, has entered into the derivative contracts with two counterparties, and the Company is a guarantor of Kodiak USA. The Company has netting arrangements with the counterparties that provides for the offset of payables against receivables from separate derivative arrangements with each counterparty in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparties. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, these instruments may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions.

The Company's commodity derivative contracts as of September 30, 2010 are summarized below:

Contract Type	Counterparty	Basis	Quantity(Bbl/d)	Strike Price ($/Bbl)	Term

Collar	BP North America	NYMEX	200	$70.00/$90.00	Mar 1 - Dec 31, 2010
Collar	Wells Fargo Bank, N.A.	NYMEX	400	$75.00/$89.20	Jan 1 - Dec 31, 2011
Collar	Wells Fargo Bank, N.A.	NYMEX	200 - 500	$70.00/$95.56	Jan 1 - Dec 31, 2011
Collar	Wells Fargo Bank, N.A.	NYMEX	400	$70.00/$95.56	Jan 1 - Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	600	$77.89	Oct 1 - Dec 31, 2010

The fair value of the derivative contracts listed above, as of September 30, 2010, is $1.1 million due the counterparties.

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The Company determines the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company's own credit rating. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

ITEM 4. CONTROLS AND PROCEDURES

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act as of September 30, 2010. On the basis of this review, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure.

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

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, the Company is a party to routine litigation and proceedings that are considered part of the ordinary course of its business. The Company is not aware of any material current, pending, or threatened litigation.

ITEM 1A. RISK FACTORS

Other than the following update, there have been no material changes to the risk factors set forth in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, as filed with the SEC on August 5, 2010. The risk factors disclosed here and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, 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:

The closing of the Acquisition under the Asset Purchase Agreement is subject to significant contingencies and closing conditions. The failure to complete the Acquisition could adversely affect the market price of our common stock and otherwise have an adverse effect on us.

The completion of the Acquisition pursuant to the Asset Purchase Agreement is subject to a number of contingencies and the satisfaction of various closing conditions, and there can be no assurance that the Acquisition will be completed. Most significantly, in order for us to close the

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Acquisition, we will need to procure the funds necessary to pay the cash portion of the purchase price. To finance the cash payment, we will need to use our existing working capital and cash flow from operations, expand the borrowing limit on our existing credit facility and establish a senior secured second lien term loan. Although we have a commitment letter from the lender to increase the facility and to establish the term loan, certain conditions and requirements must be met before closing of these financings, and we cannot give assurances as to the availability of these funds. If we are unable to secure funds to pay the purchase price of the Acquisition, we may be forced to terminate the Acquisition. Kodiak USA has placed $5.5 million in an escrow deposit account to be credited to the purchase price upon completion of the acquisition. If the Acquisition fails to close due to Kodiak USA's material breach of the Asset Purchase Agreement, including failure to procure the funds necessary to fund the Acquisition, Kodiak USA will forfeit such deposit.

If the Acquisition is not completed, we must nonetheless pay costs related to the Acquisition including, among others, legal, accounting and financial advisory, as well as certain fees and expenses related to the proposed expanded credit facility and term loan. We also could be subject to litigation related to the failure to complete the Acquisition or other factors, which may adversely affect our business, financial results and stock price. A failed transaction may result in negative publicity and/or negative impression of us in the investment community and may affect our relationships with creditors and other business partners. Additionally, the market price of our common stock may fall to the extent that the market price reflects an expectation that the Acquisition will be completed.

Our level of indebtedness is expected to significantly increase, and, as a consequence, we will have less financial flexibility.

As of September 30, 2010, we had no long or short term debt. In connection with the closing of the Acquisition, we expect to incur significant indebtedness in order to fund the cash purchase price. We are currently negotiating with a large commercial bank to increase the borrowing base of our current credit facility from $20 million to $50 million and to establish a senior secured second lien term loan with a total commitment of $40 million. In addition, in the future, we may incur additional indebtedness in order to make future acquisitions or to develop our properties. Incurring such significant indebtedness will affect our operations in several ways, including the following:

•: a significant portion of our cash flows will need to be used to service our indebtedness;
•: a high level of debt will increase our vulnerability to general adverse economic and industry conditions;
•: the covenants contained in the agreements governing such indebtedness will limit our ability to, among other things, borrow additional funds, dispose of assets and make certain investments;
•: a high level of debt could place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
•: a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay an unplanned portion of our then outstanding bank borrowings; and
•: a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

We may choose to repay a significant portion of our debt incurred in connection with the expected closing of the Acquisition by raising additional funds pursuant to an equity offering, incurring of additional debt or a combination of both. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural

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gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to repay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital. Failure to raise sufficient funds to repay our debt as and when due could expose our encumbered assets to foreclosure or other collection efforts and could result in a reduction in the pace at which we develop our properties.

In addition, our current bank borrowing base is, and any expansion thereof would be, subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so unexpectedly, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Successful completion of the Acquisition would result in an increase in the concentration of our producing properties and operations in the Williston Basin region, making us further vulnerable to risks associated with operating in one major geographic area.

As of September 30, 2010, substantially all of our production was located in the Williston Basin in northeastern Montana and northwestern North Dakota. The Acquisition consists of additional Williston Basin properties. Consequently, we are, and as a result of the Acquisition, will be further, disproportionately exposed to the risk of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

The undeveloped acreage and undeveloped proved reserves to be acquired pursuant to the Acquisition, in addition to our already large inventory of undeveloped acreage and large percentage of undeveloped proved reserves, creates additional economic risk. Such assets may not produce oil or natural gas as projected.

Our success is, and if the Acquisition closes, will be even more so, dependent upon our ability to develop significant amounts undeveloped acreage and undeveloped reserves. As of September 30, 2010, approximately 52% of our total proved reserves were undeveloped, and upon completion of the Acquisition, approximately 59% of our total proved reserves will be undeveloped. To the extent the drilling results on our current properties or on the properties to be acquired pursuant to the Acquisition are not as successful as we anticipate, natural gas and oil prices decline, or sufficient funds are not available to drill these locations and reserves, we may not capture the expected or projected value of these properties. In addition, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic, including those on the properties to be acquired pursuant to the Acquisition.

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We may not have accurately estimated the benefits to be realized from the Acquisition, or we may fail to identify problems associated with the assets to be acquired under the Asset Purchase Agreement, either of which could cause us to incur significant losses.

The expected benefits from the Acquisition may not be realized if our estimates of the potential production and net cash flows associated with the assets, once developed, are materially inaccurate or if we fail to identify problems or liabilities associated with the assets prior to closing. We are performing an inspection of the assets to be acquired, which we believe to be generally consistent with industry practices. However, the accuracy of our assessments of the assets and of our estimates are inherently uncertain. Our inspection will not likely reveal all existing or potential problems nor will it likely permit us to fully assess the deficiencies and potential recoverable reserves of the assets to be acquired. There could be environmental or other problems that are not necessarily observable even when the inspection is undertaken. If problems were to be identified after closing of the Acquisition, the Asset Purchase Agreement provides for very limited, and in certain instances, no recourse against the Seller.

Our current working capital, together with cash generated from anticipated production, will not be sufficient to support all our planned exploration and development opportunities.

We expect to rely upon cash generated from anticipated production to support a portion of our currently planned exploration and development opportunities. If we realize lower than expected cash from production, either due to lower than anticipated production levels or a decline in commodity prices from recent levels, or if the timing of our development activities results in delays in completion of our current or future wells, we may not generate cash from production in future periods in amounts sufficient to satisfy the timing and amount of that portion of our anticipated working capital requirements that we intended to fund through cash generated from production. Accordingly, if our available working capital, including the working capital anticipated through our currently planned new term debt and expanded revolving debt facilities, together with cash generated from anticipated production, is not sufficient to satisfy our planned development and exploration activities, we would need to curtail or delay our planned exploration and development activities or seek alternative sources of capital, including by means of entering into joint ventures with other exploration and production companies, sales of interests in certain of our properties or by undertaking additional financing activities (including through the issuance of equity or the incurrence of debt). We may not be able to access the capital markets or otherwise secure such additional financing on reasonable terms or at all, and financing may not continue to be available to us under our existing or new financing arrangements. If additional capital resources are unavailable, we may curtail our drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our business, financial condition and results of operation.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. RESERVED

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

Exhibit Number			Description

	2.1		Asset Purchase Agreement, entered into October 19, 2010, by and among Peak Grasslands LLC, Kodiak Oil & Gas (USA), Inc. and the Company(1)
	4.1		Form of Registration Rights Agreement among the Company, Kodiak Oil & Gas (USA) Inc. and Peak Grasslands, LLC
	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

(1): Incorporated by reference the Company current report on Form 8-K filed on October 25^, 2010.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		KODIAK OIL & GAS CORP.
November 4, 2010		/s/ LYNN A. PETERSON Lynn A. Peterson President and Chief Executive Officer
November 4, 2010		/s/ JAMES P. HENDERSON James P. Henderson Chief Financial Officer (principal financial officer)

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Kodiak Oil & Gas (KOG) Inactive 10-Q2010 Q3 Quarterly report

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