Kodiak Oil & Gas (KOG) 10-Q 2011 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2011

Commission File No. 001-32920

(Exact name of registrant as specified in its charter)

Yukon Territory	N/A
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	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 x 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 x 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 x
Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)

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

209,331,439 shares, no par value, of the Registrant’s common stock were issued and outstanding as of November 1, 2011.

KODIAK OIL & GAS CORP.

INDEX

PART 1—FINANCIAL INFORMATION		2
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	2
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	20
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	32
ITEM 4.	CONTROLS AND PROCEDURES	34
PART II—OTHER INFORMATION		34
ITEM 1.	LEGAL PROCEEDINGS	34
ITEM 1A.	RISK FACTORS	34
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	34
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	34
ITEM 4.	REMOVED AND RESERVED	34
ITEM 5.	OTHER INFORMATION	34
ITEM 6.	EXHIBITS	35
SIGNATURES		36

1

PART 1—FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

	September 30, 2011			December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents	$	78,641		$	101,198
Accounts receivable
Trade	18,049			11,328
Accrued sales revenues	11,952			4,578
Commodity price risk management asset	4,978			—
Inventory, prepaid expenses and other	20,002			18,212
Total Current Assets	133,622			135,316
Oil and gas properties (full cost method), at cost
Proved oil and gas properties	325,190			205,360
Unproved oil and gas properties	184,766			107,254
Wells in progress	71,578			21,418
Equipment and facilities	4,367			2,429
Less-accumulated depletion, depreciation, amortization, accretion and writedowns	(118,732		)	(103,799		)
Net oil and gas properties	467,169			232,662
Cash held in escrow	17,671			—
Commodity price risk management asset	4,788			—
Property and equipment, net of accumulated depreciation of $522 at September 30, 2011 and $377 at December 31, 2010	1,100			366
Deferred financing costs, net of amortization of $677 at September 30, 2011 and $83 at December 31, 2010	2,970			1,593
Total Assets	$	627,320		$	369,937
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	53,615		$	23,179
Commodity price risk management liability	—			2,248
Total Current Liabilities	53,615			25,427
Noncurrent Liabilities
Long term debt	55,000			40,000
Commodity price risk management liability	—			3,495
Asset retirement obligations	2,556			1,968
Total Noncurrent Liabilities	57,556			45,463
Total Liabilities	111,171			70,890
Commitments and Contingencies - Note 10
Stockholders’ Equity:
Common stock - no par value; unlimited authorized
Issued and outstanding: 209,331,439 shares as of September 30, 2011 and 178,168,205 shares as of December 31, 2010	586,784			407,312
Accumulated deficit	(70,635		)	(108,265		)
Total Stockholders’ Equity	516,149			299,047
Total Liabilities and Stockholders’ Equity	$	627,320		$	369,937

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONSOLIDATED FINANCIAL STATEMENTS

2

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
Revenues
Oil sales	$	28,151		$	7,964		$	62,588		$	19,374
Gas sales	1,377			167			2,387			599
Total revenues	29,528			8,131			64,975			19,973
Operating expenses
Oil and gas production	6,505			1,705			13,512			4,435
Depletion, depreciation, amortization and accretion	6,801			2,081			15,054			4,932
General and administrative	4,549			2,761			13,069			7,439
Total expenses	17,855			6,547			41,635			16,806
Operating income	11,673			1,584			23,340			3,167
Other income (expense)
Gain (loss) on commodity price risk management activities	18,806			(1,149		)	13,968			(1,101		)
Interest income (expense), net	(263		)	(76		)	(598		)	(108		)
Other income	629			2			920			5
Total other income (expense)	19,172			(1,223		)	14,290			(1,204		)
Net income	$	30,845		$	361		$	37,630		$	1,963
Earnings per common share:
Basic	$	0.15		$	0.00		$	0.20		$	0.02
Diluted	$	0.15		$	0.00		$	0.20		$	0.02
Weighted average common shares outstanding:
Basic	202,721,678			133,356,932			186,891,361			123,929,455
Diluted	205,712,033			134,947,407			189,951,979			125,533,666

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONSOLIDATED FINANCIAL STATEMENTS

3

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	For the nine months ended September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	37,630		$	1,963
Reconciliation of net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	15,054			4,932
Amortization of deferred financing costs	677			52
Unrealized (gain) loss on commodity price risk management activities, net	(15,509		)	1,101
Stock based compensation	3,514			2,778
Changes in current assets and liabilities:
Accounts receivable-trade	(6,721		)	(3,501		)
Accounts receivable-accrued sales revenue	(7,374		)	(1,631		)
Prepaid expenses and other	6,669			(983		)
Accounts payable and accrued liabilities	9,197			8,108
Net cash provided by operating activities	43,137			12,819
Cash flows from investing activities:
Oil and gas properties	(205,375		)	(45,453		)
Sale of oil and gas properties	2,132			—
Prepaid tubular goods	(15,849		)	(4,528		)
Equipment, facilities, & other	(2,817		)	(706		)
Cash held in escrow	(17,671		)	—
Net cash used in investing activities	(239,580		)	(50,687		)
Cash flows from financing activities:
Net borrowings under credit facility	15,000			—
Proceeds from the issuance of common shares	169,557			79,682
Debt and share issuance costs	(10,671		)	(4,872		)
Net cash provided by financing activities	173,886			74,810
Increase (decrease) in cash and cash equivalents	(22,557		)	36,942
Cash and cash equivalents at beginning of the period	101,198			24,885
Cash and cash equivalents at end of the period	$	78,641		$	61,827
Supplemental cash flow information
Oil & gas property accrual included in
Accounts payable and accrued liabilities	$	31,259		$	3,462
Oil & gas properties acquired through common stock	$	14,425		$	—
Cash paid for interest	$	3,766		$	79

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONSOLIDATED FINANCIAL STATEMENTS

4

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization

Description of Operations

Kodiak Oil & Gas Corp. and its subsidiary (“Kodiak” or the “Company”) is a public company listed for trading on the New York Stock Exchange under the symbol: “KOG”. The Company’s corporate headquarters are located in Denver, Colorado, USA.  The Company is an independent energy company engaged in the exploration, exploitation, development, acquisition and production of crude oil and natural gas entirely in the Rocky Mountain region of the United States.

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

Note 2—Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. All significant inter-company balances and transactions have been eliminated in consolidation. The Company’s business is transacted in US dollars and, accordingly, the financial statements are expressed in US dollars. The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information and the instructions to Form 10-Q and Regulation S-X and S-K.  In the opinion of management, all adjustments, consisting of normal recurring accruals that are considered necessary for a fair presentation of the interim financial information, have been included. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for a full year.  Kodiak’s 2010 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q.  Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in Kodiak’s 2010 Annual Report on Form 10-K.

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.  Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in ceiling test of oil and natural gas properties; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of share-based payments and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. 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 estimates under different assumptions or conditions, we believe that our estimates are reasonable.

Reclassifications

The Company has condensed certain line items within the current period financial statements, and certain prior period balances were reclassified to conform to the current year presentation accordingly.  Such reclassifications had no impact on net income, working capital or equity previously reported.

Income Taxes

The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income or loss.  The Company has not generated taxable income to date, which led the Company to provide a valuation allowance against its net deferred tax assets at December 31, 2010 and September 30, 2011 since it could not conclude that it is more likely than not that the net deferred tax assets will be fully realized on future tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; continued increases in production and proved reserves

5

from the Williston Basin.   The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

As long as the Company concludes that it will continue to have a need for a full valuation allowance against its net deferred tax assets, the Company likely will not have any income tax expense or benefit, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes. Due to the valuation allowance, no income tax expense or benefit was recorded for the three and nine months ended September 30, 2011 and 2010.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2011, the Company made no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in Canada and U.S. federal jurisdiction and various states. There are currently no Canadian or U.S. federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service, state or local tax authorities for tax years ended on or before December 31, 2008 or Canadian tax examinations by the Canadian Revenue Agency for tax years ended on or before December 31, 2003.

Recently Issued Accounting Standards

In May 2011, the FASB issued Accounting Standards Update No. 2011-04—Fair Value Measurement—Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs, which is effective for interim and annual periods beginning after December 15, 2011. The ASU is not expected to have a significant impact on the Company’s financial statements, other than additional disclosures.

Note 3—Acquisitions and Divestitures

October 28, 2011 Acquisition

On October 28, 2011, (“Closing Date”) the Company acquired a private, unaffiliated oil and gas company’s (“Seller”) interests in approximately 13,400 net acres of Williston Basin leaseholds, and related producing properties located primarily in Williams County, North Dakota along with various other related rights, permits, contracts, equipment and other assets (the “October 2011 Acquired Properties”).  The Seller received cash consideration of approximately $248.2 million and the effective date was August 1, 2011, with purchase price adjustments calculated at the Closing Date.  The total purchase included approximately $245.5 million related to the acquisition of the properties and approximately $3.3 million related to the assumption of certain working capital items.  The acquisition provided strategic additions adjacent to the Company’s core project area.  Pursuant to the Purchase and Sale Agreement the Company deposited approximately $17.7 million into escrow in September 2011, which was credited to the purchase price at the closing of the acquisition.   The $17.7 million deposit is recorded on the balance sheet under cash held in escrow.  The October 2011 Acquired Properties contributed no revenue to Kodiak for the three and nine months ended September 30, 2011.   Transaction costs related to the acquisition incurred through September 30, 2011 were approximately $100,000 and are recorded in the statement of operations within the general and administrative expenses line item.  We estimate an additional $200,000 of transaction costs will be incurred in the fourth quarter 2011.

The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of October 28, 2011.  Management has not had the opportunity to complete its assessment of the fair values of assets acquired and liabilities assumed.  The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and is subject to revision as the Company continues to evaluate the fair value of the acquisition (in thousands):

6

	October 28, 2011
Purchase Price
Consideration Given
Cash	$	17,671
Cash from credit facilities	230,542
Total consideration given	$	248,213
Preliminary Allocation of Purchase Price
Proved oil and gas properties	$	119,628
Unproved oil and gas properties	108,477
Wells in progress	17,384
Total fair value of oil and gas properties acquired	245,489
Working capital	$	3,269
Asset retirement obligation	(545		)
Fair value of net assets acquired	$	248,213
Working capital acquired was estimated as follows:
Accounts receivable	2,700
Prepaid drilling costs	754
Crude oil inventory	190
Suspense payable	(375		)
Total working capital	$	3,269

The following unaudited pro forma financial information represents the combined results for the Company and the October 2011 Acquired Properties for the three and nine months ended September 30, 2011 and 2010 as if the acquisition had occurred on January 1, 2010 (in thousands, except share data).  The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense for the three and nine months ended September 30, 2011 of $2.5 million and $4.5 million, respectively, as compared to $850,000 and $2.3 million for the three and nine months ended September 30, 2010, respectively; amortization of financing costs for both the three and nine months ended September 30, 2011 and September 30, 2010 of $267,000 and $800,000,  respectively; and all interest expense was capitalized for both the three and nine months ended September 30, 2011 and September 30, 2010 of $2.4 million and $7.1 million, respectively.  The pro forma results 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 acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	Three months ended		Three months ended			Nine months ended		Nine months ended
	September 30, 2011		September 30, 2010			September 30, 2011		September 30, 2010
Operating revenues	40,025		8,536			84,613		21,272
Net income (loss)	37,236		(199		)	49,061		(90		)
Net income (loss) per common share
Basic	$	0.18	$	0.00		$	0.26	$	0.00
Diluted	$	0.18	$	0.00		$	0.26	$	0.00

June 30, 2011 Acquisition

On June 30, 2011, (“Closing Date”) the Company acquired a private, unaffiliated oil and gas company’s (“Seller”) interests in approximately 25,000 net acres of Williston Basin leaseholds and related producing properties located in McKenzie County, North Dakota along with various other related rights, permits, contracts, equipment and other assets (the “June 2011 Acquired Properties”) for a combination of cash and stock.  The Seller received 2.5 million shares of Kodiak’s common stock valued at approximately $14.0 million and cash consideration of approximately $71.5 million. The effective date for the acquisition was April 1, 2011, with purchase price adjustments calculated at the Closing Date.  The acquisition provided strategic additions to the Company’s core positions in Koala, Smokey and Grizzly Project areas.  The June 2011 Acquired Properties contributed revenue of $825,000 to Kodiak for both the

7

three and nine months ended September 30, 2011.   Transaction costs related to the acquisition were approximately $265,000, and are recorded in the statement of operations within the general and administrative expenses line item.  Costs of $85,000 for issuing and registering with the SEC for the resale of 2.5 million shares of common stock were charged to the contributed surplus account.

The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 30, 2011.  The transaction’s final settlement was completed in September 2011 resulting in no material changes.  As a result there were no changes from our initial evaluation of the fair values of the net assets acquired in the acquisition or purchase price. The following table summarizes the purchase price and final fair value of assets acquired and liabilities assumed (in thousands):

	June 30, 2011
Purchase Price
Consideration Given
Cash from Credit Facility	$	71,506
Kodiak Oil & Gas Corp. Common Stock (2,500,000 Shares)	14,425		*
Total consideration given	$	85,931
Allocation of Purchase Price
Proved oil and gas properties	$	7,950
Unproved oil and gas properties	77,804
Total fair value of oil and gas properties acquired	85,754
Working capital	$	235
Asset retirement obligation	(58		)
Fair value of net assets acquired	$	85,931
Working capital acquired was estimated as follows:
Accounts receivable	325
Crude oil inventory	57
Suspense payable	(12		)
Accrued liabilities	(135		)
Total working capital	$	235

*The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company’s closing stock  price on the measurement date of June 30, 2011.  (2,500,000 x $5.77)

The following unaudited pro forma financial information represents the combined results for the Company and the June 2011 Acquired Properties for the three and nine months ended September 30, 2011 as if the acquisition had occurred on January 1, 2011 (in thousands, except per share data).  The June 2011 Acquired Properties commencement of production was January 20, 2011, therefore, pro forma financial information was only included for the three and nine months ended September 30, 2011.   The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $200,000 and $530,000, and interest expense of $550,000 and $1.1 million, for the three and nine months ended September 30, 2011, respectively.  The pro forma results 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 acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

8

	Three months ended		Nine months ended
	September 30, 2011		September 30, 2011
Operating revenues	29,528		66,832
Net income	30,845		37,221
Net income per common share
Basic	$	0.15	$	0.20
Diluted	$	0.15	$	0.20

November 30, 2010 Acquisition

On November 30, 2010, (“Closing Date”) the Company acquired a private, unaffiliated oil and gas company’s interests in approximately 14,500 net acres of Williston Basin leaseholds and related producing properties primarily located in McKenzie County, North Dakota (the “2010 Acquired Properties”).  The effective date for the acquisition was August 1, 2010, with purchase price adjustments calculated at the Closing Date.  The acquisition provided contiguous leaseholds with approved drilling permits near the Company’s existing acreage position.

The acquisition is accounted for using the acquisition method under ASC 805, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 30, 2010.  The transaction’s final settlement was completed in April 2011 resulting in no material changes.  As a result there were no changes from our initial evaluation of the fair values of the net assets acquired in the acquisition or purchase price.  The following table summarizes the purchase price and final fair value of assets acquired and liabilities assumed (in thousands):

	November 30, 2010
Purchase Price
Consideration Given
Cash	$	108,649
Total consideration given	$	108,649
Allocation of Purchase Price
Proved oil and gas properties	$	32,232
Unproved oil and gas properties	77,193
Total fair value of oil and gas properties acquired	109,425
Working capital	$	(541	)
Asset retirement obligation	(235		)
Fair value of net assets acquired	$	108,649
Working capital acquired was estimated as follows:
Accounts receivable	269
Crude oil inventory	63
Accrued liabilities	(873		)
Total working capital	$	(541	)

9

The following unaudited pro forma financial information represents the combined results for the Company and the 2010 Acquired Properties for the three and nine months ended September 30, 2010 as if the acquisition had occurred on January 1, 2010 (in thousands, except share data).  The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $844,000 and $1.5 million, amortization of financing costs of $72,000 and $216,000, and interest expense of $1.5 million and $4.5 million, for the three and nine months ended September 30, 2010, respectively.  The pro forma results 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 acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	Three months ended		Nine months ended
	September 30, 2010		September 30, 2010
Operating revenues	11,117		24,792
Net income (loss)	132		(512		)
Net income (loss) per common share
Basic	$	0.00	$	0.00
Diluted	$	0.00	$	0.00

Divestitures

In April 2011, the Company completed two separate sales of its interest in operated and non-operated wells, related surface equipment, and 3,046 undeveloped net acres all located in Wyoming for total cash consideration of $2.1 million.  Kodiak was relieved of all reclamation liabilities associated with the producing properties.  As a result of the divestiture, the Company’s asset retirement obligation decreased by $610,000.  Additionally, Kodiak retained an overriding royalty interest in certain leases conveyed.   No gain or loss was recognized on the sale and the proceeds reduced the full cost pool.

Note 4—Earnings 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.  Diluted net income per common share includes shares of restricted stock  units, and the potential dilution that could occur upon exercise of 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).

In accordance with ASC 260-10-45, Share-Based Payment Arrangements and Participating Securities and the Two-Class Method, the Company’s unvested restricted stock shares are deemed participating securities, since these shares would be entitled to participate in dividends declared on common shares.  During periods of net income, the calculation of earnings per share for common stock exclude income attributable to the restricted stock shares from the numerator and exclude the dilutive impact of those shares from the denominator. During periods of net loss, no effect is given to the participating securities because they do not share in the losses of the Company.

The performance based restricted stock units and unexercised stock options are not participating securities, since these shares are not entitled to participate in dividends declared on common shares.  The number of potentially dilutive shares attributable to the performance based restricted stock units is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the performance measurement period.  Please refer to Note 5 — Share-Based Payments under the heading Restricted Stock Units and Performance Awards for additional discussion.

10

The table below sets forth the computations of basic and diluted net income per share for the three and nine months ended September 30, 2011 and September 30, 2010 (in thousands, except per share data):

	For the three months ended September 30,						For the nine months ended September 30,
	2011			2010			2011			2010
Numerator:
Basic net income	$	30,845		$	361		$	37,630		$	1,963
Income allocable to participating securities	(3		)	—			(5		)	—
Diluted net income	$	30,842		$	361		$	37,625		$	1,963
Denominator:
Basic weighted average common shares outstanding	202,721,678			133,356,932			186,891,361			123,929,455
Effect of dilutive securities
Options to purchase common shares	4,866,658			3,213,917			5,051,658			3,213,917
Assumed treasury shares purchased	(2,156,303		)	(1,623,441		)	(2,271,040		)	(1,609,706		)
Unvested restricted stock units	280,000			—			280,000			—
Diluted weighted average commons shares outstanding	205,712,033			134,947,408			189,951,979			125,533,666
Basic net income per share	$	0.15		$	—		$	0.20		$	0.02
Diluted net income per share	$	0.15		$	—		$	0.20		$	0.02

The following options and unvested restricted shares, which could be potentially dilutive in future periods, were not included in the computation of diluted net income per share because the effect would have been anti-dilutive for the periods indicated:

	For the three months ended September 30,		For the nine months ended September 30,
	2011	2010	2011	2010
Anti-dilutive shares	1,334,500	4,300,000	1,149,500	4,300,000

Note 5—Share-Based Payments

The Company has granted options to directors, officers, and employees of the Company under the 2007 Stock Incentive Plan (the “Plan”), amended on June 3, 2010 and further amended June 15, 2011. The Plan authorizes the Company to issue stock options, stock appreciation rights (SARs), restricted stock and restricted stock units, performance awards, other stock grants and other stock-based awards to any employee, consultant, independent contractor, director or officer providing services to the Company or to an affiliate of the Company.  The maximum number of shares of common stock available for issuance under the Plan is equal to 14% of the Company’s issued and outstanding shares of common stock, as calculated on January 1 of each respective year, subject to adjustment as provided in the Plan.  As of January 1, 2011, the maximum number of shares issuable under the Plan, including those previously issued thereunder, was approximately 24.9 million shares.  The June 15, 2011 amendment referenced above limited the number of shares of common stock available for granting incentive stock options under the Plan to 24.5 million shares, eliminated the limitation on the number of shares available for granting restricted stock and clarified the duration of the restriction limiting the grant of performance-based awards to individual Plan participants.

11

Stock Options

Total compensation expense related to the stock options of $734,000 and $2.7 million was recognized during the three and nine months ended September 30, 2011, respectively, as compared to $1.0 million and $2.5 million for the three and nine months ended September 30, 2010, respectively.   As of September 30, 2011, there was $5.9 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted-average period of 2.27 years.

Compensation expense related to stock options is calculated using the Black Scholes-Merton valuation model. Expected volatilities are based on the historical volatility of Kodiak’s common stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.  The following assumptions were used for the Black-Scholes-Merton model to calculate the share-based compensation expense for the period presented:

	For the nine  months ended		For the year ended,
	September 30, 2011		December 31, 2010
Risk free rates	1.22 - 2.57%		0.70 - 3.02%
Dividend yield	0%		0%
Expected volatility	91.14 - 93.40%		95.01 - 102.11%
Weighted average expected stock option life	6.01 years		4.55 years
The weighted average fair value at the date of grant for stock options granted is as follows:
Weighted average fair value per share	$	4.82	$	2.29
Total options granted	1,260,500		2,937,000
Total weighted average fair value of options granted	$	6,070,905	$	6,732,504

A summary of the stock options outstanding as of January 1, 2011 and September 30, 2011 is as follows:

			Weighted
			Average
	Number		Exercise
	of Options		Price
Balance outstanding at January 1, 2011	6,489,917		$	2.73
Granted	1,260,500		6.31
Canceled	(601,525	)	3.54
Exercised	(947,734	)	2.91
Balance outstanding at September 30, 2011	6,201,158		$	3.47
Options exercisable at September 30, 2011	3,734,658		$	2.81

12

At September 30, 2011, stock options outstanding were as follows:

Exercise Price	Number of  Shares	Weighted Average  Remaining Contractual  Life (Years)
$0.36 - $1.00	460,000	7.25
$1.01 - $2.00	895,917	2.61
$2.01 - $3.00	1,128,000	7.89
$3.01 - $4.00	1,994,741	5.05
$4.01 - $5.00	105,000	9.32
$5.01 - $6.00	283,000	9.62
$6.01 - $7.20	1,334,500	8.55
	6,201,158	6.41

The aggregate intrinsic value of both outstanding and vested options as of September 30, 2011 was $12.6 million based on the Company’s September 30, 2011 closing common stock price of $5.21 per share. The total grant date fair value of the shares vested during 2011 was $3.7 million.

Restricted Stock Units and Performance Awards

Total compensation expense related to restricted stock units (“RSUs”) and performance awards (“PAs”) of $294,000 and $826,000 was recognized during the three and nine months ended September 30, 2011, respectively, as compared to $12,000 and $300,000 for the three and nine months ended September 30, 2010, respectively.   As of September 30, 2011, there was $1.2 million of total unrecognized compensation cost related to the RSUs, which is expected to be amortized over a weighted-average period of 1.91 years.

During 2011, the Company awarded tandem grants of 105,000 performance based RSUs and 52,500 PAs to employees pursuant to the Company’s 2007 Plan.  Subject to the satisfaction of certain performance-based conditions, the RSUs and PAs vest one-quarter per year over a four year service date and the Company began recognizing compensation expense related to these grants beginning in 2011 over the vesting period. Additionally, the Company awarded tandem grants of 22,500 shares of restricted stock and 11,250 PAs to its Board of Directors pursuant to the Company’s 2007 Plan. These restricted stock shares and PAs vest after a one year service date and the Company will recognize compensation expense related to these grants beginning in 2011 over the vesting period. The Company recognizes compensation cost for performance based grants on a tranche level and service-based grants on a straight-line basis over the requisite service period for the entire award. The fair value of restricted stock and RSU grants is based on the stock price on the grant date and the Company assumes no annual forfeiture rate.

The PAs are payable in cash, except the Company may, in its discretion, determine to pay out the PAs on the vesting date through the issuance of shares of the Company’s common stock.  Consequently, as the PAs will likely be settled in cash, a liability was recorded in the amount of $330,000 at September 30, 2011. The liability for the PAs is remeasured at each quarter.

As of September 30, 2011, there were 280,000 unvested RSUs and 22,500 unvested restricted stock shares with a combined weighted average grant date fair value of $6.59 per share.  The total fair value vested during 2011 was $623,000.   A summary of the RSUs and restricted stock shares outstanding as of January 1, 2011 and September 30, 2011 is as follows:

			Weighted
			Average
	Number		Grant Date
	of Shares		Fair Value
Non-vested at January 1, 2011	183,000		$	6.47
Granted	220,500		6.50
Forfeited	—		—
Vested	(101,000	)	6.17
Non-vesting and outstanding at September 30, 2011	302,500		$	6.59

13

Note 6—Credit Facility

Credit Agreement

Kodiak Oil & Gas (USA) Inc. (the “Borrower”), a wholly owned subsidiary of Kodiak Oil & Gas Corp., is a party to a credit agreement with Wells Fargo Bank, N.A. (“Wells Fargo”), originally entered into on May 24, 2010 (the “Original Credit Agreement”). For a description of the terms of the Original Credit Agreement, see Note 6 to our interim financial statements for the quarter ended June 30, 2010.  The Original Credit Agreement was subsequently amended by the First Amendment to Credit Agreement dated November 30, 2010 between the Borrower and Wells Fargo, by the Second Amendment to Credit Agreement (the “Second Amendment”) dated April 13, 2011 between the Borrower and Wells Fargo and by the Amended and Restated Credit Agreement (the “Third Amendment”) dated October 28, 2011 between the Borrower and Wells Fargo, BMO Harris Financing, Inc., KeyBank, N.A., Royal Bank of Canada, and Credit Suisse AG (the Original Credit Agreement as amended by the foregoing, the “Credit Agreement”).

As of September 30, 2011, the maximum credit amount was $200.0 million, which was increased to $750.0 million on October 28, 2011 pursuant to the Third Amendment. The borrowing base has also increased during the first nine months of 2011. Pursuant to the Second Amendment, in April 2011, the borrowing base was increased from $50.0 million to $75.0 million.  In July 2011, pursuant to an elective redetermination of the borrowing base, the borrowing base was increased to $110.0 million.  In October 2011, pursuant to the Third Amendment, the borrowing base was increased to $225.0 million.  Redetermination of the borrowing base under the Credit Agreement occurs semi-annually, on April 1 and October 1.  Additionally, the Company may elect a redetermination of the borrowing base one time during any six month period.  As of September 30, 2011, the Credit Agreement had a maturity date of May 24, 2014, which maturity date was subsequently extended under the Third Amendment to October 28, 2016.

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. Pursuant to the Second Amendment, the Applicable Margin was reduced on the alternate base rate from a sliding scale of 1.25% to 2.25%, to a sliding scale of 0.75% to 1.75%, depending on borrowing base usage. The Applicable Margin was reduced on the adjusted LIBO rate from a sliding scale of 2.25% to 3.25%, to 1.75% to 2.75%, depending on borrowing base usage.  The grid below shows the Applicable Margin options depending on the applicable Borrowing Base Utilization Percentage (as defined in the Credit Agreement) as of September 30, 2011 and the date hereof:

Borrowing Base Utilization Grid

Borrowing Base Utilization Percentage	<25.0	%	>25.0% <50.0	%	>50.0% <75.0	%	>75.0% <90.0	%	>90.0	%
Eurodollar Loans	1.75	%	2.00	%	2.25	%	2.50	%	2.75	%
ABR Loans	0.75	%	1.00	%	1.25	%	1.50	%	1.75	%
Commitment Fee Rate	0.375	%	0.375	%	0.50	%	0.50	%	0.50	%

The Second Amendment also amended the terms of the Original Credit Agreement to, among other things, decrease the borrowing base increase fee from 1.0% to 0.5% and reduce the commitment fee from a flat fee of 0.50% to a sliding scale of 0.375% to 0.50%, depending on borrowing base usage.

The Credit Agreement contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (a) limitations on liens and incurrence of debt covenants; (b) limitations on dividends, distributions, redemptions and restricted payments covenants; (c) limitations on investments, loans and advances covenants; and (d) limitations on the sale of property, mergers, consolidations and other similar transactions covenants.

As of September 30, 2011, the Credit Agreement also contained financial covenants (a) requiring the Borrower to comply with a current ratio of consolidated current assets (including unused borrowing capacity) to consolidated current liabilities of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (as defined in the Credit Agreement) of 4.0 to 1.0 for the four fiscal quarters ending on the last day of any fiscal quarter ending on or before December 31, 2010 and to 3.75 to 1.0 for the four fiscal quarters ending on the last day of each fiscal quarter thereafter; and (b) requiring the Company to maintain a ratio of EBITDAX to certain interest expenses of at least 3.0 to 1.0 for the four fiscal quarters ending on the last day of any fiscal quarter.  On October 28, 2011, pursuant to the Third Amendment, the leverage ratio covenant was amended to require the Borrower to maintain, on the last day of each quarter, a ratio of total debt to EBITDAX for the quarter period ending on such date of not greater than 4.00 to 1.00 for the term of the loan and the covenant requiring the Borrower to maintain a ratio of EBITDAX to certain interest expenses was eliminated.  As of September 30, 2011 and the date hereof, the Company was and is in compliance with all covenants under the Credit Agreement.

14

Subsequent to September 30, 2011, the Third Amendment amended the Original Credit Agreement to, among other things, (a) provide for a subfacility for swingline loans in an amount equal to $15.0 million, each on customary terms and conditions; (b) increase the amount available for standby letters of credit from the lesser of the remaining borrowing base or $5.0 million, to $25.0 million; (c) restrict the Borrower’s payment, prepayment or redemption of debt outstanding under the Second Lien Credit Agreement, except the Borrower may make interest payments thereunder and make repayments thereof from proceeds of the issuance of senior notes; (d) allow for certain reductions in the borrowing base upon a sale of assets that has an aggregate negative effect on the borrowing base greater than 5% of the then current value and upon the issuance of senior notes; (e) require certain minimum payments in the event of prepayment; and (f) require the Borrower to enter hedging agreements necessary to support the borrowing base.

As of September 30, 2011, the Company had no outstanding borrowings under the Credit Agreement. On October 28, 2011, to fund the acquisition of the October 2011 Acquired Properties, the Company drew down $186.0 million under the Credit Agreement.  Therefore, as of October 28, 2011, approximately $39.0 million was available to borrow under the Credit Agreement.  Borrowings under the Credit Agreement currently accrue interest at a rate of approximately 3% and are guaranteed by the Company and collateralized by the Borrower’s oil and gas producing properties, the Borrower’s personal property and the equity interests of the Borrower held by the Company.

Second Lien Credit Agreement

The Borrower is also a party to a second lien credit agreement with Wells Fargo Energy Capital, Inc. (“Wells Fargo Energy”), originally entered into on November 30, 2010 (the “Original Second Lien Credit Agreement”). For a description of the terms of the Original Second Lien Credit Agreement, see Note 8 to our audited financial statements for the year ended December 31, 2010.  The Original Second Lien Credit Agreement was subsequently amended by the Agreement and Amendment No. 1 to Second Lien Credit Agreement (the “Second Lien Amendment No. 1”) dated July 15, 2011 between the Borrower and Wells Fargo Energy and by the Amended and Restated Second Lien Credit Agreement (the “Second Lien Amendment No. 2”) dated October 28, 2011 between the Borrower and Wells Fargo Energy, The Prudential Insurance Company of America, Prudential Retirement Insurance and Annuity Company, and Pruco Life Insurance Company (the Original Second Lien Credit Agreement as amended by the foregoing, the “Second Lien Credit Agreement”).

The initial commitment under the Second Lien Credit Agreement was originally $40.0 million and was increased in July 2011 to $55.0 million and again increased in October 2011 to $100 million.  As of September 30, 2011, the Second Lien Credit Agreement had a maturity date of November 24, 2014, which maturity date was subsequently extended under the Second Lien Amendment No. 2 to April 28, 2017.

Interest on the loans under the Second Lien Credit Agreement accrues based on one of the following two fluctuating reference rates: (a) the LIBO rate (which is primarily based on the London interbank market rate), subject to a floor of 2.5%, and (b) the alternate base rate (which is primarily based on Wells Fargo’s “prime” rate). As of September 30, 2011, loans that accrued interest at the LIBO rate were subject to an additional margin of 8%, and loans that accrued interest at the alternate base rate were subject to an additional margin of 7%.  On October 28, 2011, pursuant to the Second Lien Amendment No. 2, such additional margins were each reduced by 1%, such that loans that accrued interest at the LIBO rate were subject to an additional margin of 7%, and loans that accrued interest at the alternate base rate were subject to an additional margin of 6%.

The Second Lien Credit Agreement contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to restrictions or requirements with respect to additional debt, liens, investments, hedging activities, acquisitions, dividends, mergers, sales of assets, transactions with affiliates and capital expenditures. In addition, the Second Lien Credit Agreement includes financial covenants substantially similar to those under the Credit Agreement, including the amendments thereto, except that the Second Lien Amendment No. 2 amended the leverage ratio covenant to require the Borrower to maintain, on the last day of each quarter, a ratio of total debt to EBITDAX (as defined in the Second Lien Credit Agreement) for the quarter period ending on such date of not greater than 4.50 to 1.00 for the term of the loan. The Second Lien Credit Agreement also contains an additional covenant addressing limitations on the Borrower’s ratio of total net cash flow of the Company’s proved reserves discounted at 10% to Total Debt (each as defined in the Second Lien Credit Agreement). As of September 30, 2011 and the date hereof, the Company was and is in compliance with all covenants under the Second Lien Credit Agreement.

The Second Lien Amendment No. 1 also amended the Original Second Lien Credit Agreement to provide for earlier prepayment of outstanding borrowings, but was superseded by the Second Lien Amendment No. 2, which provides that loans under the Second Lien Credit Agreement may be prepaid, provided the prepayment includes a 0-3% premium based upon when the prepayment occurs. The Second Lien Amendment No. 2 also amended the Original Second Lien Credit Agreement to require certain minimum prepayment amounts.

15

As of September 30, 2011, the Company had $55.0 million in outstanding borrowings under the Second Lien Credit Agreement, which accrued interest at a rate of approximately 10.5%. Subsequent to quarter end, on October 28, 2011, to fund the acquisition of the October 2011 Acquired Properties, the Company borrowed an additional $45.0 million under the Second Lien Credit Agreement, which, in addition to the $55.0 million previously borrowed, results in an aggregate of $100.0 million borrowed under the Second Lien Credit Agreement as of the date hereof.  The borrowings under the Second Lien Amendment No. 2 currently accrue interest at a rate of approximately 9.5% and are guaranteed by the Company and collateralized by a second lien on the Borrower’s oil and gas producing properties, the Borrower’s personal property and the equity interests of the Borrower held by the Company.

Deferred Financing Costs

As of September 30, 2011, the Company recorded deferred financing costs of $3.6 million related to the closing of its First Lien Credit Agreement and Second Lien Credit Agreement and respective amendments.  Deferred financing costs include origination, legal and engineering fees incurred in connection with the Company’s credit facilities, which are being amortized over the four-year term of the credit facilities.  The Company recorded amortization expense for the three and nine months ended September 30, 2011 of $290,000 and $677,000, respectively, as compared to $22,000 and $52,000 for both the three and nine months ended September 30, 2010, respectively.  On October 28, 2011 in conjunction with the amended and restated credit facilities, the Company incurred an additional $4.1 million of deferred financing costs.

Interest Incurred Under the First and Second Lien Credit Agreement

Total interest expense incurred during the three and nine months ended September 30, 2011 was approximately $1.5 million and $3.8 million, respectively, as compared to $64,000 and $79,000 for the three and nine months ended September 30, 2010.  The Company capitalized interest costs of $1.5 million and $3.8 million for the three and nine months ended September 30, 2011. The Company did not capitalize any interest for the three and nine months ended September 30, 2010.

Note 7—Asset Retirement Obligations

The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depreciated over the estimated life of the producing property.

	For the nine  months ended			For the year ended
	September 30, 2011			December 31, 2010
	(In thousands)
Balance beginning of period	$	1,968		$	1,060
Liabilities incurred	1,066			849
Liabilities settled	(610		)	(67		)
Accretion expense	132			126
Balance end of period	$	2,556		$	1,968

Note 8— Commodity Derivative Instruments

Through its wholly-owned subsidiary Kodiak Oil & Gas (USA) Inc., the Company has entered into commodity derivative instruments, 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.  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

16

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 does not enter into derivative contracts for speculative purposes.

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 Oil & Gas (USA) Inc. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the 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, 2011 are summarized below:

Contract Type	Counterparty	Basis(1)	Quantity(Bbl/d)	Strike Price ($/Bbl)	Term
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	$85.00/$117.73	Mar 1—Dec 31, 2011
Collar	Wells Fargo Bank, N.A.	NYMEX	400	$70.00/$95.56	Jan 1—Dec 31, 2012
Collar	Wells Fargo Bank, N.A.	NYMEX	230	$85.00/$117.73	Jan 1—Dec 31, 2012
Collar	Shell Trading (U.S.)	NYMEX	500	$85.00 - $117.00	Aug 1—Dec 31, 2013

Contract Type	Counterparty	Basis(1)	Quantity(Bbl/d)	Swap Price ($/Bbl)	Term
Swap	Wells Fargo Bank, N.A.	NYMEX	135	$84.00	Jan 1—Dec 31, 2011
Swap	Wells Fargo Bank, N.A.	NYMEX	130	$90.28	Jul 1—Dec 31, 2011
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$85.00	Nov 1 - Dec 31, 2011
Swap	Shell Trading (U.S.)	NYMEX	250	$85.01	Nov 1 - Dec 31, 2011
2011 Total/Average			326	$85.62
Swap	Wells Fargo Bank, N.A.	NYMEX	100	$84.00	Jan 1—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	136	$88.30	Jan 1—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	24	$90.28	Jan 1—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$85.00	Nov 1 - Dec 31, 2012
Swap	Shell Trading (U.S.)	NYMEX	250	$85.01	Nov 1 - Dec 31, 2012
2012 Total/Average			1010	$85.47
Swap	Wells Fargo Bank, N.A.	NYMEX	79	$84.00	Jan 1—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	427	$88.30	Jan 1—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	24	$90.28	Jan 1—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$85.00	Nov 1 - Dec 31, 2013
Swap	Shell Trading (U.S.)	NYMEX	250	$85.01	Nov 1 - Dec 31, 2013
2013 Total/Average			1280	$86.14
Swap	Wells Fargo Bank, N.A.	NYMEX	69	$84.00	Jan 1—Dec 31, 2014
Swap	Wells Fargo Bank, N.A.	NYMEX	360	$88.30	Jan 1—Dec 31, 2014
Swap	Wells Fargo Bank, N.A.	NYMEX	21	$90.28	Jan 1—Dec 31, 2014
2014 Total/Average			450	$87.73
Swap	Wells Fargo Bank, N.A.	NYMEX	59	$84.00	Jan 1—Oct 31, 2015
Swap	Wells Fargo Bank, N.A.	NYMEX	317	$88.30	Jan 1—Sept 30, 2015
Swap	Wells Fargo Bank, N.A.	NYMEX	46	$90.28	Jan 1—Oct 31, 2015
2015 Total/Average (Through October)			390	$87.81

Subsequent to September 30, 2011, the Company entered into additional commodity derivative contracts which are summarized below:

Contract Type	Counterparty	Basis(1)	Quantity(Bbl/d)	Strike Price ($/Bbl)	Term
Collar	Shell Trading (U.S.)	NYMEX	1,000	$75.00 - $89.25	Nov 1—Dec 31, 2011
Swap	Wells Fargo Bank, N.A.	NYMEX	400 - 1,000	$85.07	Nov 1—Dec 31, 2015

(1) NYMEX refers to quoted prices on the New York Merchantile Exchange

17

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

Underlying Commodity	Location on  Balance Sheet	As of September 30, 2011		As of December 31, 2010
Crude oil derivative contract	Current assets	$	4,978	$	—
Crude oil derivative contract	Noncurrent assets	$	4,788	$	—
Crude oil derivative contract	Current liabilities	$	—	$	2,248
Crude oil derivative contract	Noncurrent liabilities	$	—	$	3,495

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

	For the three  months ended  September 30, 2011			For the three  months ended  September 30, 2010			For the nine  months ended  September 30, 2011			For the nine  months ended  September 30, 2010
Unrealized gain (loss) on oil contracts	$	19,012		$	(1,149	)	$	15,509		$	(1,101	)
Realized gain (loss) on oil contracts	(206		)	—			(1,541		)	—
Gain (loss) on commodity price risk management activities	$	18,806		$	(1,149	)	$	13,968		$	(1,101	)

Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are recognized on the consolidated statement of operations. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of income.

Note 9—Fair Value Measurements

ASC Topic 820, Fair Value Measurement and Disclosure, 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;

·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.  There were no nonfinancial assets or liabilities measured at fair value on a non-recurring basis at September 30, 2011 or December 31, 2010.

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, 2011 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements Using
	Level 1	Level 2	Level 3	Total
Assets:
Commodity price risk management asset	—	9,766	—	9,766

18

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, 2011, 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 and payable, and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s long-term debt approximates its fair value as it bears interest at variable rates over the term of the loan.

Note 10—Commitments and Contingencies

Lease Obligations

The Company leases office space in Denver, Colorado and Dickinson, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on April 30, 2016. The Dickinson, North Dakota lease expires December 31, 2013.  Total rental commitments under non-cancelable leases for office space were $2.2 million at September 30, 2011.

Drilling Rigs

As of September 30, 2011 the Company was subject to commitments on five drilling rig contracts.  One of the contracts expires in late 2011, one in 2012, and three in 2013.  In the event of early termination under all of these contracts, the Company would be obligated to pay an aggregate amount of approximately $37.5 million as of September 30, 2011 as required under the varying terms of such contracts.

Pressure Pumping Services

In the first quarter of 2011, the Company entered into a two-year agreement with a pressure-pumping service company commencing on September 1, 2011 that would provide 24-hour per day frac crew availability for 14 days per month, to be reconciled on a quarterly basis.  In the event of early contract termination under the agreement, the Company would be obligated to pay approximately $23.0 million as of September 30, 2011.  In October 2011, the Company amended the agreement to provide 24-hour frac crew availability for 30 days per month.  The new terms will commence in January 2012.  Under the new agreement in the event of early contract termination, the Company would be obligated to pay approximately $36.0 million for the first six months and then the obligation would reduce monthly thereafter.

Guarantees

The Company may issue debt securities in the future that the Company’s wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., may guarantee. Any such guarantee is expected to be full, unconditional and joint and several. The Company has no independent assets or operations nor does it have any other subsidiaries. There are no significant restrictions on the ability of the Company to receive funds from the Company’s subsidiary through dividends, loans, and advances or otherwise.

Note 11—Common Stock

Equity Offering

In July 2011, the Company issued 27,600,000 shares of common stock in a public offering, which included the full exercise of the underwriters’ over-allotment option of 3,600,000 for gross proceeds of approximately $168.4 million. The net proceeds of the offering, after deducting underwriting discounts and commissions and Kodiak’s estimated offering expenses, were approximately $159.4 million.  The common stock was issued pursuant to an automatic shelf registration statement on Form S-3 (No. 333-173520) that was filed with the SEC on April 15, 2011 and amended on June 29, 2011.  The Company used $60.0 million of the net proceeds from the offering to repay debt outstanding under the First Lien Credit Agreement.

19

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

Forward-Looking Statements

The information discussed in this quarterly report on Form 10-Q 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:

·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;

·future capital requirements and uncertainty of obtaining additional funding when needed on terms acceptable to us;

·unsuccessful drilling and completion activities and the possibility of resulting write-downs;

·geographical concentration of our principal operations;

·constraints imposed on our business and operations by our credit agreements and our ability to generate sufficient cash flows to repay our debt obligations;

·availability of borrowings under our credit agreements;

·increases in the cost of drilling, completion and gas gathering or other costs of production and operations;

·our ability to successfully drill wells that produce oil or natural gas in commercially viable quantities;

·failure to meet our proposed drilling schedule;

·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;

·reliance on limited number of customers;

·title defects to our properties and inability to retain our leases;

·incorrect estimates of proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of properties that we acquire;

·our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;

·our ability to retain key members of our senior management and key technical employees, and conflicts of interests with respect to our directors;

20

·marketing and transportation constraints;

·federal and tribal regulations and laws;

·our current level of indebtedness and the effect of any increase in our level of indebtedness;

·risks in connection with potential acquisitions and the integration of significant acquisitions;

·price volatility of oil and natural gas prices, and the effect that lower prices may have on our net income and stockholders’ equity;

·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;

·impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;

·effects of competition;

·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 the section entitled “Risk Factors” included in our Annual Report on Form 10-K. 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 section and elsewhere in this 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 the Williston Basin of North Dakota and secondarily in the Green River Basin of Wyoming and Colorado. Kodiak’s corporate strategy is to internally identify unconventional prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential unconventional oil and natural gas prospects.

Our revenue and future growth rate depend on factors largely beyond our control such as economic, political and regulatory developments and competition from other sources of energy. Oil and gas prices historically have been volatile and may fluctuate widely in the future.  Our business is particularly dependent on the price of oil.   Lower oil prices may not only decrease our revenues, but may also reduce the amount of oil that we can produce economically and therefore could potentially lower our reserve bookings. A substantial or extended decline in oil prices may result in impairments of our proved oil and gas properties and may materially or adversely affect our future business, cash flows, results of operations, liquidity or ability to finance planned capital expenditures. Lower oil prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher oil prices may result in significant non-cash mark-to-market losses being recognized on our commodity derivatives, resulting in the possibility of net losses.

21

Williston Basin

Williston Basin in Western North Dakota and Eastern Montana:  As of September 30, 2011, we owned an interest in approximately 145,000 gross (92,000 net) acres in this geologic basin. Our primary target within the Williston Basin is the Bakken Pool consisting of the middle Bakken and Three Forks formations, collectively “Bakken”.  During the first nine months of 2011, we invested capital expenditures of approximately $163.2 million (inclusive of $8.0 million allocated to producing properties from our acquisition of the June 2011 Acquired Properties) related to drilling and completion operations and $84.3 million (inclusive of $77.8 million allocated to undeveloped acreage related to our acquisition of the June 2011 Acquired Properties) related to land leasing activities.  Additionally, as further described below, on October 28, 2011, we closed an acquisition of oil and gas properties and associated assets for consideration of approximately $248.2 million, including approximately $3.3 million related to the assumption of certain working capital items. With the addition of the October 2011 Acquired Properties, we now own an interest in approximately 105,000 net acres in the Williston Basin and operate, or have an interest in, a total of 65 gross (33.4 net) producing wells.

Green River Basin

Vermillion Basin of southwest Wyoming:  Our secondary operating area consists of leaseholdings in the Green River Basin located in an area referred to as the Vermillion Basin. As of September 30, 2011, we owned a non-operating interest in approximately 41,000 gross (17,000 net) acres in this geologic basin that is prospective for multiple gas bearing reservoirs including the Almond Sandstone and the Baxter Shale, a 3,000-foot-thick, condensate and gas-prone interval that is also referred to as the Niobrara Shale in other parts of Wyoming and Colorado.  During the third quarter 2011, we participated with a 12.5% non-operated working interest in a development well drilled in the Almond Formation within the Whiskey Canyon Unit in Sweetwater County, Wyoming.

Recent Developments

Operational Update

Our five operated drilling rigs are presently drilling ahead on multi-well drilling pads. Two rigs are drilling in Dunn County, N.D. and three rigs are drilling in McKenzie County, N.D, with two of these rigs drilling in our Smokey project area and one rig drilling in our Grizzly project area.

During the third quarter and into October 2011, we completed 7 gross (5.0 net) operated wells and 5 gross (2.4 net) non-operated wells in our Dunn County project area.  Results from such wells can be found in the table below.  Completion activities are under way in our Charging Eagle project area in Dunn County, N.D. where two wells are currently being fracture stimulated.  We anticipate that our well completion efforts will continue on pace the remainder of the year with a total of 9 gross (6.1 net) operated wells projected to be completed by year end 2011, including two gross (0.8 net) wells properties acquired as discussed below.  Furthermore, we expect additional drilling and completion activity to continue on our non-operated lands in Dunn County through the end of the year.

Acquisition of Williston Basin Properties

During October 2011, we closed the previously announced acquisition of oil and gas properties and associated assets located in the Williston Basin from a private, unaffiliated oil and gas company.  The purchase price for the properties was $245.5 million, including approximately $9.8 million of purchase price adjustments to reflect the August 1, 2011 effective date of the acquisition.  In addition, we paid $3.3 million for certain working capital items.   Pursuant to the purchase and sale agreement, the Company deposited $17.7 million into escrow in September 2011, which was credited to the purchase price at the closing of the acquisition.   We funded the remaining balance of the purchase price through borrowings under our Amended and Restated Credit Agreement and Amended and Restated Second Lien Credit Agreement, as further discussed below.

The acquisition included approximately 13,400 net mineral acres primarily in Williams County, North Dakota.  Included in the acquisition was an operated working interest in the following: 7 gross (5.1 net) producing wells; 4 gross (2.2 net) wells waiting on completion; four drilling pads that have been built for drilling scheduled in early 2012; and minor non-operated interest in approximately 17 wells.  Completion work on two gross (0.8 net) operated wells is scheduled to commence in November with other completions to continue through year-end.  A salt water disposal well has been drilled on the lands, and water gathering pipelines have been constructed over the majority of the lands acquired.  Furthermore, gas pipelines are in place, and gas is currently being sold.  We anticipate mobilizing one of our existing five rigs onto the acquired lands in the first quarter of 2012.

22

Additional Borrowing Availability under Our Credit Facilities

On October 28, 2011, in conjunction with the closing of the acquisition of the October 2011 Acquired properties, the Company completed an amended and restated Credit Agreement with Wells Fargo Bank, N.A. and its Second Lien Credit Agreement with Wells Fargo Energy Capital, Inc.  The borrowing base under the Amended and Restated Credit Agreement was increased from $110.0 million to $225.0 million and the initial commitment under the Amended and Restated Second Lien Credit Agreement was increased from $55.0 million to $100.0 million.  Additionally, the interest rate on the Amended and Restated Second Lien Credit Agreement was reduced by 100.0 basis points.  The Company used the additional $45.0 million from the Amended and Restated Second Lien Credit Agreement and used $185.5 million from its Amended and Restated Credit Agreement to close the acquisition of the October 2011 Acquired Properties.   As a result, the Company’s current borrowings under the Amended and Restated Credit Agreement and the Amended and Restated Second Lien Credit Agreement are $186.0 and $100.0 million, respectively.  We currently have approximately $39.0 million available for borrowing under our Amended and Restated Credit Agreement and anticipate that this borrowing base will continue to expand as we complete additional wells.

Dedicated Pressure Pumping Team

In October 2011, we amended our existing agreement with Halliburton Energy Services whereby we will have a full time 24 hour dedicated crew commencing January 2012.  We anticipate having approximately 21 days available to us through year end and then moving into a full time arrangement in 2012.   This agreement formalizes our ongoing relationship with Halliburton and ensures continuation of the close relationship we have historically maintained.   As a result of the agreement, we believe that we have enhanced our ability to execute our completion program.

Williston Basin Drilling and Completion Activities

Please refer to the table below that provides a tabular presentation of data pertinent to our Williston Basin drilling and completion activities targeting the Bakken during 2010 and 2011 (gas is converted on a 6 Mcf to 1 barrel of oil basis):

23

Kodiak Oil & Gas Corp.

North Dakota (Bakken and Three Forks) Drilling and Completion Activities

	WI /	Completion	IP 24- Hour Test		Daily Production (BOE/d)				Gas / Oil Ratio	Well
Well Name	NRI (%)	Date	BOE/D		30 Day	60 Day	90 Day	180 Day	(GOR)	Status (2)
Dunn County, ND
MC #13-34-28-1H	59 / 48	Sep-10	1,906		1,082	1,074	995	723	700	PW
MC #13-34-28-2H	59 / 48	Aug-10	2,055		1,259	1,073	932	655	600	PW
TSB #14-21-33-15H	50 / 41	Dec-10	2,050		877	790	706	701	700	FW
TSB #14-21-33-16H3	50 / 41	Dec-10	1,042		603	444	—	—	550	FW
TSB #14-21-4H	50 / 41	Dec-10	1,196		656	470	397	—	600	PW
TSB #14-21-16-2H	50 / 41	Apr-11	N/A		194	164	—	—	600	PW
TSB #2-24-12-2H	50 / 41	Sep-11	1,752	(1)	—	—	—	—	600	FW
SC #2-24-25-15H	96 / 79	Sep-11	3,028		1,449	—	—	—	730	FW
TSB #2-24-12-1H3	50 / 41	Sep-11	3,083		1,398	—	—	—	500	FW
SC #12-10-11-9H	97 / 79	Oct-11	2,950		—	—	—	—	700	FW
SC #12-10-11-9H3	97 / 79	Q311	2,982		—	—	—	—	700	FW
SC #2-8-17-15H	46 / 38	Q411	—		—	—	—	—	—	WOC
CE #15-22-15-4H	56 / 45	Q411	—		—	—	—	—	—	Completing
CE #15-22-15-3H3	56 / 45	Q411	—		—	—	—	—	—	Completing
SC #2-8-17-14H3	46 / 38	Q411	—		—	—	—	—	—	WOC
SC #2-24-25-16H	96 / 79	2012	—		—	—	—	—	—	WOC
CE #15-14-11-4H	56 / 45	2012	—		—	—	—	—	—	Drilling
SC #9-2-3-5H	99 / 81	2012	—		—	—	—	—	—	Mobilizing
McKenzie County, ND
Grizzly #1-27H-R	74 / 60	Sep-10	507		210	204	196	189	800	PW
Grizzly #13-6H	68 / 56	Feb-11	399		122	120	119	—	350	PW
Koala #9-5-6-5H	95 / 78	Apr-11	3,042		1,377	1,165	1,103	—	1200	FW
Koala #9-5-6-12H3	95 / 78	Apr-11	2,327		1,072	1,063	980	—	1300	FW
Koala #3-2-11-14H	52 / 42	Jul-11	3,412		1,337	1,230	—	—	1250	FW
Koala #3-2-11-13H	53 / 43	Jul-11	3,021		1,144	1,004	—	—	1200	FW
Koala #2-25-36-15H	66 / 53	Q411	—		—	—	—	—	—	WOC
Koala #2-25-36-14H3	66 / 53	Q411	—		—	—	—	—	—	WOC
Koala #2-25-36-13H3	66 / 53	Q411	—		—	—	—	—	—	WOC
Smokey #15-22-15-2H	85 / 69	Q411	—		—	—	—	—	—	WOC
Smokey #15-22-34-15H	63 / 51	Q411	—		—	—	—	—	—	WOC
Grizzly #3-25-13-3H	50 / 41	2012	—		—	—	—	—	—	Drilling
Smokey #3-6-7-14H	56 / 45	2012	—		—	—	—	—	—	Drilling
Smokey #16-20-17-2H	94 / 75	2012	—		—	—	—	—	—	Drilling
Williams County, ND
Mildred #9-4-1H	45 / 35	Q411	—		—	—	—	—	—	WOC
State #16-21-1H	36 / 28	Q411	—		—	—	—	—	—	WOC
Long #1-12-1H	73 / 56	2012	—		—	—	—	—	—	WOC

(1) 14 stages completed initially, with the remaining stages completed in October 2011.	FW = Flowing Well
(2) Well Status is as of November 3, 2011.	PW = Pumping Well
	WOC = Waiting on Completion

24

2011 Capital Expenditures and Budget

Our 2011 capital expenditure budget of $230.0 million (not including acquisitions) is subject to various factors, including market conditions, oilfield services and equipment availability, commodity prices and drilling results and is comprised of the following:

·$185.0 million for the drilling and completion of operated wells and related infrastructure and other capital expenditures. In the nine month period ended September 30, 2011, we spent approximately $ 132.3 million on operated properties.  Year-to-date through September 30, 2011, we have completed 8 gross (5.6 net) operated wells and drilled 13 gross (9.9 net) operated wells.

·$40.0 million is allocated to non-operated drilling activity in Dunn County. We have spent $23.0 million year-to-date related to the drilling and completion progress on 6 gross (2.9 net) wells.

·$6.5 million for leasehold expenditures spent in the nine month period ended September 30, 2011.

·This capital budget does not include our two recent Williston Basin acquisitions of the October 2011 Acquired Properties or the June 2011 Acquired Properties totaling $331.4 million.

Capital Resources

Our 2011 drilling program is designed to provide flexibility in identifying suitable well locations and in the timing and size of capital investment. We anticipate funding the remaining 2011 capital program with the following sources, all of which are reflected after giving effect to the amount paid for the October 2011 Acquired Properties:

·Our existing working capital of $80.0 million, including $78.6 million of cash and equivalents as of September 30, 2011.

·Availability under our Credit Agreement of $39.0 million.  Further, we anticipate our borrowing base under our Credit Agreement and Second Lien Credit Agreement to continue to increase with additional proved oil and gas reserves as a result of our drilling and completion activity.

·Our operating cash flows, which are expected to fund an increasing portion of our capital expenditures.

We are in the process of finalizing our 2012 drilling program and identifying our potential sources of funding, which we expect will include an increase in our operating cash flows, an increase in our borrowing base under our Credit Agreement and commitments under our Second Lien Credit Agreement as reserves increase, and additional debt and equity sources if and to the extent available.  We anticipate running a five operated rig drilling program through the first part of 2012 and are evaluating the potential of adding a sixth rig once the winter weather abates.

We cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings will be sufficient to fund our anticipated capital expenditures. 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 be 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. 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.

Our Properties

Williston Basin (168,000 gross and 105,000 net acres)

We are currently operating a five rig drilling program on lands in Dunn and McKenzie Counties, N.D.  Year-to-date through September 30, 2011, we have completed 8 gross (5.6 net) operated wells and drilled 13 gross (9.9 net) operated wells. During the fourth quarter 2011, we anticipate drilling 7 gross (6.1 net) wells and completing 9 gross (6.6 net) wells including the October 2011 Acquired Properties.

Our joint venture partner on a portion of our Dunn County leasehold continues to operate a two-rig drilling program.  Year-to-date we have participated in the completion of 5 gross (2.4 net) wells and the drilling of 5 gross (2.4 net) wells on these non-operated lands.  During the fourth quarter of 2011, we anticipate participating in the drilling of 4 gross (2.0 net) wells on these non-operated lands.

25

Our leasehold is largely contiguous and by virtue of our high working interest and operatorship, we can control the development pace and location of our surface facilities. We believe this strategy, combined with pad drilling and long laterals, will maximize the efficiency of our drilling and completion programs as well as minimize the infrastructure required to connect our wells to sales pipelines and water disposal facilities.  As a result, we are able to plan our locations to minimize the number of wells required to hold our acreage by establishing production within the primary terms of our leases and therefore do not have a significant number of leases with short term expiration.

Infrastructure build-out continues to improve.  The majority of our wells in Dunn County are connected to pipeline infrastructure to transport oil, gas and water.  The ability to sell and process gas from these wells continues to be constrained due to process plant capacity restrictions.  Some of these restrictions are being eliminated as additional capacity has been brought on-line during the fourth quarter and will continue to expand going into 2012.  In McKenzie County, the majority of our wells have been connected to gas pipelines and, in some cases, oil pipelines.  Pipeline construction continues at a steady pace, and we expect most of our wells to have pipeline access for both oil and gas by year-end.

Our Leasehold

As of September 30, 2011, we had several hundred lease agreements representing approximately 186,000 gross and 109,000 net acres primarily in the Williston and Green River Basins. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

	Undeveloped Acreage(1)		Developed Acreage(2)		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Green River Basin
Wyoming	26,201	5,849	1,520	908	27,721	6,757
Colorado	7,339	4,960	—	—	7,339	4,960
Williston Basin
Montana	3,255	1,870	3,240	2,446	6,495	4,316
North Dakota	112,869	70,676	25,760	16,875	138,629	87,551
Other Basins
Wyoming	5,591	5,591	—	—	5,591	5,591
Acreage Totals	155,255	88,946	30,520	20,229	185,775	109,175

(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.

We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Substantially all of our proved oil and natural gas properties are pledged as collateral for borrowings under our Amended and Restated Credit Agreement and Amended and Restated Second Lien Credit Agreement.

26

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 during the current year and 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, 2011	160	80
December 31, 2012	18,863	11,870
December 31, 2013	22,640	15,939
December 31, 2014	32,166	15,850
Total	73,829	43,739

Operating Results

Production and Sales Volumes, Average Sales Prices, and Production Costs

The Bakken is the only field (as such term is used within the meaning of applicable regulations of the SEC) that contains more than 15% of our total proved reserves. At December 31, 2010, this field contained 99% of our total proved reserves, nearly all of which are located in Dunn and McKenzie Counties. The following table discloses our oil and gas production and sales volumes from the Bakken field, from our other fields combined and in total, for the periods indicated:

	For the three months ended			For the nine months ended
	September 30, 2011		September 30, 2010	September 30, 2011	September 30, 2010
Sales Volume (Bakken):
Oil (Bbls)	333,788		111,518	699,475	263,638
Gas (Mcf)	139,740		1,458	242,153	5,342
Sales Volume (Other):
Oil (Bbls)	7,411		9,026	22,874	21,314
Gas (Mcf)	-4,720	(2)	35,884	42,193	125,882
Sales Volume (Total):
Oil (Bbls)	341,199		120,544	722,350	284,952
Gas (Mcf)	135,020		37,342	284,346	131,224
Sales volumes (BOE)	363,703		126,768	769,741	306,823
Natural Gas flared (Mcf) (1):	241,492		83,908	473,441	175,222
Total production volume (Total):
Oil (Bbls)	352,144		121,222	731,678	287,246
Gas (Mcf)	376,512		121,250	757,787	306,446
Production volumes (BOE)	414,896		141,431	857,976	338,320

(1) Includes production of natural gas that is not included in our sales volumes.  All flared gas is related to the Bakken field.

(2) Negative amount as a result of the settlement of a gas imbalance on properties previously sold .

27

Sales prices received, and production costs per sold BOE for the three and nine months ended September 30, 2011 and 2010 are summarized in the following table:

	For the three months ended					For the nine months ended
	September 30, 2011			September 30, 2010		September 30, 2011			September 30, 2010
Sales Price:
Gas ($/Mcf) (1)	$	10.20		$	4.47	$	8.39		$	4.56
Oil ($/Bbls)	$	82.51		$	66.07	$	86.65		$	67.99
Commodity Price Risk Management Activities ($/Sales BOE):
Realized gain (loss)	$	(0.56	)	$	9.06	$	(2.00	)	$	3.59
Production costs ($/Sales BOE):
Lease operating expenses	$	8.14		$	6.25	$	7.46		$	6.72
Production and property taxes	$	8.83		$	7.05	$	9.34		$	7.44
Gathering, transportation, marketing	$	0.91		$	0.16	$	0.75		$	0.29
DDA	$	18.70		$	16.42	$	19.56		$	16.07

(1) Average gas price received at the wellhead includes proceeds from natural gas liquids under percentage of proceeds contracts.

Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010

Oil sales revenues.  Oil sales revenues increased by $20.2 million to $28.2 million for the three months ended September 30, 2011, as compared to oil sales of $8.0 million for the same period in 2010. Oil sales volume increased 183% to 341.2 thousand barrels (MBbls) in the third quarter of 2011 as compared to 120.5 MBbls in the third quarter of 2010. The volume increase is due to our ongoing Bakken development program.  Also, contributing to the increase in sales revenue was the increase in the average price we realized on the sale of our oil.  Our net price received increased from $66.07 per barrel for the quarter ended September 30, 2010 to $82.51 per barrel for the quarter ended September 30, 2011.

Natural gas sales revenues.  Natural gas revenues increased by $1.2 million to $1.4 million for the three months ended September 30, 2011, as compared to natural gas sales of $167,000 for the same period in 2010. Natural gas sales volumes increased to 135,020 Mcf in the third quarter of 2011 compared to 37,342 Mcf in the same period in 2010. The average price we realized on the sale of our natural gas for the three months ended September 30, 2011 was $10.20 per Mcf compared to $4.47 per Mcf for the same period in 2010. The increase in our natural gas sales volumes is largely the result of production and sales of associated gas from our Bakken properties, which was partially offset by a decrease due to the sale of certain Wyoming properties that historically comprised the majority of our natural gas production and sales. The price realized from sales of our natural gas increased due to the growth of our gas sales from our Bakken properties, which has a higher natural gas liquids content compared to our Wyoming properties.  Although the majority of our gas from the Bakken wells-to-date has been flared, late in 2010, we began connecting our wells to third-party pipelines that gather and transport the gas to processing plants and sales pipelines. We expect that a majority of our remaining wells will be connected to gas pipelines by the end of 2011, which will allow us to increase the related sales revenue. Industry-wide in the Williston Basin, there is currently a shortage of gas gathering and processing capacity.  Such shortage has limited our ability to sell our gas production.  During fourth quarter 2011and into 2012, we expect that additional third-party facilities will come online which should allow additional gas volumes to be gathered, processed and sold.

Gain on commodity price risk management activities.  Primarily due to the decrease in forward crude oil prices during the third quarter of 2011, for the three months ended September 30, 2011, we incurred a total gain on our commodity price risk management activities of $18.8 million. The gain on commodity price risk management activities is a result of our hedging program used to mitigate our exposure to commodity price fluctuations that can adversely affect our ability to fund our capital expenditure budget or other obligations. The gain on these activities was comprised of approximately $200,000 of realized losses for transactions that were settled in the third quarter of 2011 and $19.0 million of unrealized gains for the mark-to-market valuation of forward transactions. The unrealized gain is a non-cash adjustment for the value of our risk management transactions at September 30, 2011. These transactions will continue to change in value, and we will likely expand our hedging program. As such, we expect our net income to continue to reflect the volatility of commodity price forward markets. Our cash flows are not affected by unrealized gains

28

and losses on commodity risk management activities, but rather, will be affected when gains or losses are realized upon settlement of the underlying transactions at the current market prices at that time.

Oil and gas production expense.  Our oil and gas production expense increased by $4.8 million to $6.5 million for the quarter ended September 30, 2011 as compared to $1.7 million for the same period in 2010.  The increase is due to a $2.3 million increase in production taxes, a $2.2 million increase in lease operating expenses (“LOE”), and a $300,000 increase in gathering, transportation and marketing expenses.  The production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue.  LOE increased year over year due to an increase in the number of wells that we operate and which we participate.  On a per unit basis, LOE increased from $6.25 per barrel sold in the third quarter 2010 to $8.14 per barrel sold in the third quarter of 2011. The increase in LOE was primarily attributed to an increase in water disposal costs and expenses related to winter preparation.  As a result of the increase in the number of wells completed during the third quarter 2011 compared to the same period in the prior year we incurred more expense in water disposal costs.  Throughout 2011, we have incurred additional costs to repair roads from the severe weather conditions that resulted in flooding during the spring of 2011.  In the third quarter 2011, we incurred costs in order to complete scheduled winter preparation maintenance work that we believe will improve the reliability of our production.   Finally, the increase in gathering expense is due to additional wells that have been connected to gathering lines with related gathering fees.

Depletion, depreciation, amortization and accretion (“DDA”) expense.  Our DDA expense increased by $4.7 million to $6.8 million for the three months ended September 30 2011, from $2.1 million for the same period in 2010. This increase is due to increased volumes sold in the third quarter 2011, as sales increased by approximately 237,000 BOE over the same period. On a per unit basis, DDA increased from $16.42 per barrel sold in the third quarter of 2010 to $18.70 per barrel sold for the same period in 2011. This increase in the DDA rate was primarily the result of the allocation of the purchase price to producing properties related to our acquisitions in the fourth quarter of 2010 and second quarter of 2011.

General and administrative (“G&A”) expense.  G&A expense increased by $1.7 million to $4.5 million for the quarter ended September 30, 2011 from $2.8 million for the same period in 2010. This increase is primarily due to the growth in personnel and related costs as we have expanded our operational activities related to the Bakken development. Total employees increased to 60 at September 30, 2011 from 30 at September 30, 2010.  Additionally, in the third quarter of 2011, we incurred approximately $100,000 in transaction costs related to the acquisition of the October 2011 Acquired Properties in the Williston Basin.

Our G&A expense includes the non-cash expense for share-based compensation for stock options and restricted stock unit grants under our 2007 Stock Incentive Plan. For the three months ended September 30, 2011, this expense was $1.0 million as compared to $1.1 million for the same period in 2010.

Operating income.  Our operating income was approximately $11.7 million for the quarter ended September 30, 2011, as compared to approximately $1.6 million for the quarter ended September 30, 2010. This 637% increase in operating income is attributed to our on-going successful completions of wells in our Bakken play as well as crude oil price improvement from the third quarter of 2010 to the third quarter of 2011.

Net income.  Our net income was approximately $30.8 million for the quarter ended September 30, 2011, as compared to net income of approximately $361,000 for the quarter ended September 30, 2010. Our net income was positively impacted by increased oil and gas production along with increased crude oil prices, resulting in oil and gas revenues of $29.5 million.  Additionally, a $19.0 million unrealized gain on commodity price risk management was recorded as a result of the decrease in forward crude oil prices from June 30, 2011 to September 30, 2011.

Nine Months Ended September 30, 2011 Compared to the Nine Months Ended September 30, 2010

Oil sales revenues.  Oil sales revenues increased by $43.2 million to $62.6 million for the nine months ended September 30, 2011, as compared to oil sales of $19.4 million for the same period in 2010.  Oil sales volume increased 153% to 722.4 MBbls for the nine months ended 2011 as compared to 285.0 MBbls for the nine months ended 2010. The volume increase is due to our ongoing Bakken development program.  However, these volumes were negatively impacted in the first half of 2011 by severe winter conditions which caused delays in transportation. Also contributing to the increase in sales revenue was the increase in the average price we realized on the sale of our oil. Our net price received increased from $67.99 per barrel for the nine months ended September 30, 2010, to $86.65 per barrel for the nine months ended September 30, 2011.

Natural gas sales revenues.  Natural gas revenues increased by approximately $1.8 million to $2.4 million for the nine months ended September 30, 2011, as compared to natural gas sales of $599,000 for the same period in 2010. Natural gas sales volumes increased to 284,300 Mcf in the first nine months of 2011 as compared to 131,200 Mcf in the same period in 2010. The average price we realized on the sale of our natural gas was $8.39 per Mcf for the nine months ended September 30, 2011 compared to $4.56 per Mcf for the same period in 2010. The increase in our natural gas sales volumes is largely a result of production and sales of

29

associated gas from our Bakken properties offset by a decline of our Wyoming assets that historically contributed a majority of our natural gas production.  The price realized from sales of our natural gas increased due to the growth of our gas sales from our Bakken properties, which has a higher natural gas liquids content compared to our Wyoming properties.  Although the majority of our gas from the Bakken wells-to-date has been flared, late in 2010, we began connecting our wells to third-party pipelines that gather and transport the gas to processing plants and sales pipelines. We expect that a majority of our remaining wells will be connected to gas pipelines by the end of 2011 which will allow us to capture the related sales revenue.  Industry-wide in the Williston basin, there is currently a shortage of gas gathering and processing capacity which has limited our ability to sell our gas production.  During fourth quarter 2011 and into 2012, we expect that additional third-party facilities will come online which should allow additional gas volumes to be gathered, processed and sold.

Gain on commodity price risk management activities.  Primarily due to the decrease in forward crude oil prices at September 30, 2011, we incurred a total gain on our commodity price risk management activities of $14.0 million.   During third quarter 2011, we entered into several crude oil swaps and costless collars.   Subsequent to entering into these contracts crude oil pricing continued to decrease.  The gain on commodity price risk management activities is a result of our hedging program used to mitigate our exposure to commodity price fluctuations that may inhibit our ability to fund our capital expenditure budget or other obligations.  The gain on these activities was comprised of approximately $1.5 million of realized losses for transactions that were settled in the first nine months of 2011 and $15.5 million of unrealized gains for the mark-to-market valuation of forward transactions. The unrealized gain is a non-cash adjustment for the value of our risk management transactions at September 30, 2011. These transactions will continue to change in value and we will likely add to our hedging program. Therefore, we expect our net income to continue to reflect the volatility of commodity price forward markets. Our cash flows are not affected by unrealized gains and losses on commodity risk management activities, but rather, will be affected when gains or losses are realized upon settlement of the underlying transactions at the current market prices at that time.

Oil and gas production expense.  Our oil and gas production expense increased by $9.1 million to $13.5 million for the nine months ended September 30, 2011 as compared to $4.4 million for the same period in 2010. The increase is due to a $4.9 million increase in production taxes, a $3.7 million increase in lease operating expenses, and a $491,000 increase in gathering, transportation and marketing expenses. The production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue. LOE increased year over year due to a higher number of wells that we operate or participate in. On a per unit basis, LOE increased from $6.72 per barrel sold in the first nine months of 2010 to $7.46 per barrel sold in the first nine months of 2011. As a result of the increase in the number of wells completed during the first nine months of 2011 compared to the same period in the prior year we incurred more expense in water disposal costs.  Additionally, throughout 2011, we incurred additional costs to repair roads from the severe weather conditions that resulted in flooding during the spring of 2011.

Depletion, depreciation, amortization and accretion expense.  Our depletion, depreciation, amortization and accretion expense increased by $10.1 million to $15.0 million for the nine months ended September 30, 2011, from $4.9 million for the same period in 2010. This increase is due to increased volumes sold in 2011 as sales increased by approximately 463,000 BOE over the same period.  On a per unit basis, DDA increased from $16.07 per barrel sold in the first nine months of 2010 to $19.56 per barrel sold in the first nine months of 2011. This increase is due to increased well costs as compared to reserves as estimated in our annual reserve report. Beginning late 2010, we began predominantly completing our wells using a greater number of fracture stimulation stages and increased volumes of proppant. These factors have increased the well completion costs, but we believe that the higher upfront costs will generate overall higher returns through greater production volumes and total oil and gas reserves. Currently, because of the early stages of development of our Bakken play, our reserves, especially for undeveloped locations, include the increased well costs, but not the improved reserves. We believe that as our improved results are reflected in our future estimated reserves, the DDA rate per unit will decrease over time. Also contributing to the increased DDA rate, is the allocation of the purchase price to producing properties related to our acquisitions in the fourth quarter of 2010 and second quarter of 2011.

General and administrative expense.  G&A expense increased by $5.6 million to $13.1 million for the nine months ended September 30, 2011, from $7.4 million for the same period in 2010. This increase is primarily due to the growth in personnel and related costs as we have expanded our operational activities related to the Bakken development.  Total employees increased to 60 at September 30, 2011, from 30 at September 30, 2010.  Additionally, in the second and third quarter of 2011, we incurred approximately $365,000 in transactions costs related to the acquisition of the June 2011 Acquired Properties and the October 2011 Acquired Properties in the Williston Basin.

Our G&A expense includes the non-cash expense for share-based compensation for stock options and restricted stock unit grants under our 2007 Stock Incentive Plan.  For the nine months ended September 30, 2011, this expense was $3.5 million as compared to $2.8 million for the same period in 2010.

30

Operating income.  Our operating income was approximately $23.3 million for the nine months ended September 30, 2011, as compared to approximately $3.2 million for the nine months ended September 30, 2010. This 637% increase in operating income is attributed to our on-going successful completions of wells in our Bakken play as well as crude oil price improvement for the first nine months of 2011 compared to the first nine months of 2010.

Net income.  Our net income was approximately $37.6 million for the nine months ended September 30, 2011, as compared to net income of approximately $2.0 million for the nine months ended September 30, 2010. Our net income was positively impacted by increased oil and gas production along with increased crude oil prices, resulting in oil and gas revenues of $65.0 million.  Additionally, a $15.5 million unrealized gain on commodity price risk management was recorded for the mark-to-market valuation of forward transactions.

Commitments and Contingencies

For a discussion of our commitments and contingencies, see Note 10 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, 2011 and December 31, 2010.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. A summary of the company’s significant accounting policies is included in Note 2 to the Company’s consolidated financial statements in the 2010 Annual Report. Certain of the company’s accounting policies are considered critical, as these policies are the most important to the depiction of the Company’s financial statements and require significant, difficult or complex judgments, often employing the use of estimates about the effects of matters that are inherently uncertain. Such policies are summarized in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in our annual report on Form 10-K for the year ended December 31, 2010.  There have been no significant changes in the Company’s application of its critical accounting policies during the first nine months of 2011 other than income taxes as discussed below.

 Income Taxes - Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, consistent and sustained pre-tax earnings, sustained or continued improvements in oil and natural gas commodity prices, consistent, meaningful production and proved reserves from our Williston Basin project.   The Company currently has a full valuation allowance and will continue to evaluate whether the valuation allowance is needed in future reporting periods.

Recently Issued Accounting Pronouncements

For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to the Recently Issued Accounting Standards footnote in the Notes to Condensed Consolidated Financial Statements.

Effects of Pricing and Inflation

The demand for oil field products and services has increased in the Williston Basin beginning in 2010 and continuing into 2011.  Typically, as prices for oil and natural gas increase, so do the associated costs.  As oil and natural gas prices decline, we would expect associated costs to decline, however, there may be a lag or the changes may be disproportionate to the lower prices.  Material

31

changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel.  While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

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. The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. We manage this commodity price risk exposure through the use of derivative financial instruments entered into with third-party counterparties. Currently, we utilize swaps and “no premium” collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes.

We use no premium collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements. These contracts are settled monthly. When the settlement price (the market price for oil or natural gas on the settlement date) for a period is above the ceiling price, we pay our counterparty. When the settlement price for a period is below the floor price, our counterparty is required to pay us. All hedges are accounted for using mark-to-market accounting.

We also use swaps to fix the sales price for our anticipated future oil production. Upon settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating market price, as defined in each instrument. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to us.

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 Oil & Gas (USA) Inc., is currently a party to derivative contracts with two counterparties, and the Company is a guarantor of Kodiak Oil & Gas (USA) Inc. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the 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, 2011 are summarized below:

Contract Type	Counterparty	Basis(1)	Quantity(Bbl/d)	Strike Price ($/Bbl)	Term
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	$85.00/$117.73	Mar 1—Dec 31, 2011
Collar	Wells Fargo Bank, N.A.	NYMEX	400	$70.00/$95.56	Jan 1—Dec 31, 2012
Collar	Wells Fargo Bank, N.A.	NYMEX	230	$85.00/$117.73	Jan 1—Dec 31, 2012
Collar	Shell Trading (U.S.)	NYMEX	500	$85.00 - $117.00	Aug 1—Dec 31, 2013

32

Contract Type	Counterparty	Basis(1)	Quantity(Bbl/d)	Swap Price ($/Bbl)	Term
Swap	Wells Fargo Bank, N.A.	NYMEX	135	$84.00	Jan 1—Dec 31, 2011
Swap	Wells Fargo Bank, N.A.	NYMEX	130	$90.28	Jul 1—Dec 31, 2011
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$85.00	Nov 1 - Dec 31, 2011
Swap	Shell Trading (U.S.)	NYMEX	250	$85.01	Nov 1 - Dec 31, 2011
2011 Total/Average			326	$85.62
Swap	Wells Fargo Bank, N.A.	NYMEX	100	$84.00	Jan 1—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	136	$88.30	Jan 1—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	24	$90.28	Jan 1—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$85.00	Nov 1 - Dec 31, 2012
Swap	Shell Trading (U.S.)	NYMEX	250	$85.01	Nov 1 - Dec 31, 2012
2012 Total/Average			1010	$85.47
Swap	Wells Fargo Bank, N.A.	NYMEX	79	$84.00	Jan 1—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	427	$88.30	Jan 1—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	24	$90.28	Jan 1—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$85.00	Nov 1 - Dec 31, 2013
Swap	Shell Trading (U.S.)	NYMEX	250	$85.01	Nov 1 - Dec 31, 2013
2013 Total/Average			1280	$86.14
Swap	Wells Fargo Bank, N.A.	NYMEX	69	$84.00	Jan 1—Dec 31, 2014
Swap	Wells Fargo Bank, N.A.	NYMEX	360	$88.30	Jan 1—Dec 31, 2014
Swap	Wells Fargo Bank, N.A.	NYMEX	21	$90.28	Jan 1—Dec 31, 2014
2014 Total/Average			450	$87.73
Swap	Wells Fargo Bank, N.A.	NYMEX	59	$84.00	Jan 1—Oct 31, 2015
Swap	Wells Fargo Bank, N.A.	NYMEX	317	$88.30	Jan 1—Sept 30, 2015
Swap	Wells Fargo Bank, N.A.	NYMEX	46	$90.28	Jan 1—Oct 31, 2015
2015 Total/Average (Through October)			390	$87.81

Subsequent to September 30, 2011, the Company entered into an additional commodity derivative contract which is summarized below:

Contract Type	Counterparty	Basis(1)	Quantity(Bbl/d)	Strike Price ($/Bbl)	Term
Collar	Shell Trading (U.S.)	NYMEX	1,000	$75.00 - $89.25	Nov 1—Dec 31, 2011
Swap	Wells Fargo Bank, N.A.	NYMEX	400 - 1,000	$85.07	Nov 1—Dec 31, 2015

(1) NYMEX refers to quoted prices on the New York Merchantile Exchange

The following table details the fair value of the derivatives financial instruments as of September 30, 2011 and December 31, 2010, by category (in thousands):

Underlying Commodity	Location on  Balance Sheet	As of September 30, 2011		As of December 31, 2010
Crude oil derivative contract	Current assets	$	4,978	$	—
Crude oil derivative contract	Noncurrent assets	$	4,788	$	—
Crude oil derivative contract	Current liabilities	$	—	$	2,248
Crude oil derivative contract	Noncurrent liabilities	$	—	$	3,495

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 the 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.

33

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, 2011. 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

There have been no material changes to the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2010, as filed with the SEC on March 3, 2011 and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, as filed with the SEC on August 4, 2011. The risk factors disclosed here and in our Annual Report on Form 10-K for the year ended December 31, 2010 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, in addition to the other information set forth in this quarterly report, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

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

None.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.  REMOVED AND RESERVED

ITEM 5.  OTHER INFORMATION

None.

34

ITEM 6.  EXHIBITS

Exhibit Number	Description
2.1	Purchase and Sale Agreement between BTA Oil Producers LLC, and Kodiak Oil & Gas (USA) Inc. dated September 27, 2011*
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
101	The following materials are filed herewith: (i) XBRL Instance, (ii) XBRL Taxonomy Extension Schema, (iii) XBRL Taxonomy Extension Calculation, (iv) XBRL Taxonomy Extension Labels, (v) XBRL Taxonomy Extension Presentation, and (vi) XBRL Taxonomy Extension Definition. In accordance with Rule 406T of Regulation S-T, the information in these exhibits is furnished and deemed not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Exchange Act of 1934, and otherwise is not subject to liability under these sections and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by the specific reference in such filing.

* Schedules (and similar attachments) to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Registrant agrees to furnish a supplemental copy of any omitted schedule (or similar attachment) to the Securities and Exchange Commission upon request.

35

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 3, 2011	/s/ LYNN A. PETERSON
	Lynn A. Peterson President and Chief Executive Officer
November 3, 2011	/s/ JAMES P. HENDERSON
	James P. Henderson Chief Financial Officer (principal financial officer)

36