Kodiak Oil & Gas (KOG) 10-Q 2012 Q1 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 March 31, 2012

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 x	Accelerated filer o
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

263,530,643 shares, no par value, of the Registrant’s common stock were issued and outstanding as of May 1, 2012.

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	21
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	33
ITEM 4.	CONTROLS AND PROCEDURES	34
PART II—OTHER INFORMATION		35
ITEM 1.	LEGAL PROCEEDINGS	35
ITEM 1A.	RISK FACTORS	35
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	35
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	35
ITEM 4.	MINE SAFETY DISCLOSURES	35
ITEM 5.	OTHER INFORMATION	35
ITEM 6.	EXHIBITS	36
SIGNATURES		37

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PART 1—FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

	March 31, 2012			December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	24,905		$	81,604
Cash held in escrow	—			12,194
Accounts receivable
Trade	37,348			28,835
Accrued sales revenues	38,183			21,974
Commodity price risk management asset	688			—
Inventory, prepaid expenses and other	20,012			24,294
Total Current Assets	121,136			168,901
Oil and gas properties (full cost method), at cost:
Proved oil and gas properties	1,117,174			598,065
Unproved oil and gas properties	556,642			263,462
Wells in progress	76,280			78,505
Equipment and facilities	16,115			11,186
Less-accumulated depletion, depreciation, amortization, and accretion	(161,594		)	(135,586		)
Net oil and gas properties	1,604,617			815,632
Cash held in escrow	—			691,764
Commodity price risk management asset	426			—
Property and equipment, net of accumulated depreciation of $727 at March 31, 2012 and $618 at December 31, 2011	1,418			1,276
Deferred financing costs, net of accumulated amortization of $15,669 at March 31, 2012 and $15,029 at December 31, 2011	21,435			21,904
Total Assets	$	1,749,032		$	1,699,477
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	138,970		$	78,402
Accrued interest payable	18,775			5,808
Commodity price risk management liability	20,220			11,925
Total Current Liabilities	177,965			96,135
Noncurrent Liabilities:
Credit facilities	—			100,000
Senior notes	650,000			650,000
Commodity price risk management liability	21,470			10,035
Asset retirement obligations	4,975			3,627
Total Noncurrent Liabilities	676,445			763,662
Total Liabilities	854,410			859,797
Stockholders’ Equity:
Common stock - no par value; unlimited authorized
Issued and outstanding: 263,530,643 shares as of March 31, 2012 and 257,987,413 shares as of December 31, 2011	997,268			944,070
Accumulated deficit	(102,646		)	(104,390		)
Total Stockholders’ Equity	894,622			839,680
Total Liabilities and Stockholders’ Equity	$	1,749,032		$	1,699,477

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Revenues:
Oil sales	$	76,814		$	13,020
Gas sales	3,122			314
Total revenues	79,936			13,334
Operating expenses:
Oil and gas production	17,300			2,574
Depletion, depreciation, amortization and accretion	26,295			3,721
General and administrative	7,898			4,718
Total operating expenses	51,493			11,013
Operating income	28,443			2,321
Other income (expense):
Loss on commodity price risk management activities	(23,340		)	(9,692		)
Interest income (expense), net	(4,627		)	33
Other income	1,268			103
Total other income (expense)	(26,699		)	(9,556		)
Net income (loss)	$	1,744		$	(7,235	)
Net income (loss) per common share:
Basic	$	0.01		$	(0.04	)
Diluted	$	0.01		$	(0.04	)
Weighted average common shares outstanding:
Basic	262,660,642			178,451,574
Diluted	266,586,016			178,451,574

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net income (loss)	$	1,744		$	(7,235	)
Reconciliation of net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	26,295			3,721
Amortization of deferred financing costs	640			187
Unrealized loss on commodity price risk management activities, net	18,616			9,350
Stock-based compensation	2,435			1,539
Changes in current assets and liabilities:
Accounts receivable-trade	(8,513		)	1,474
Accounts receivable-accrued sales revenue	(16,209		)	12
Prepaid expenses and other	(924		)	(295		)
Accounts payable and accrued liabilities	28,657			(1,589		)
Accrued interest payable	467			(12		)
Cash held in escrow	3,343			—
Net cash provided by operating activities	56,551			7,152
Cash flows from investing activities:
Oil and gas properties	(704,344		)	(22,423		)
Prepaid tubular goods	—			(10,084		)
Equipment, facilities and other	(10,329		)	(618		)
Cash held in escrow	30,000			—
Net cash used in investing activities	(684,673		)	(33,125		)
Cash flows from financing activities:
Repayments under credit facilities	(100,000		)	—
Proceeds from the issuance of common shares	1,108			947
Cash held in escrow	670,615			—
Debt and share issuance costs	(300		)	(17		)
Net cash provided by financing activities	571,423			930
Decrease in cash and cash equivalents	(56,699		)	(25,043		)
Cash and cash equivalents at beginning of the period	81,604			101,198
Cash and cash equivalents at end of the period	$	24,905		$	76,155
Supplemental cash flow information:
Oil & gas property accrual included in Accounts payable and accrued liabilities	$	84,452		$	11,589
Oil & gas property acquired through common stock	$	49,798		$	—
Cash paid for interest	$	3,536		$	1,124

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization

Description of Operations

Kodiak Oil & Gas Corp. 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 2011 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 2011 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. The Company evaluates our estimates on an on-going basis and bases our estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes 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, statements of cash flows, 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 and has incurred a cumulative book loss over the last three fiscal years, which led the Company to provide a valuation allowance against both U.S. and Canadian net deferred tax assets since it could not conclude that it is more likely than not that the net deferred tax assets will be fully realized. 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

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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 from the Williston Basin. The Company will continue to evaluate whether a valuation allowance on a separate country basis 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 months ended March 31, 2012 and 2011.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2012, 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, 2007 or Canadian tax examinations by the Canadian Revenue Agency for tax years ended on or before December 31, 2000. Although certain tax years are closed under the statute of limitations, tax authorities can still adjust tax losses being carried forward to open tax years.

Recently Issued Accounting Standards

In May 2011, the FASB issued Accounting Standards Update 2011-04 (“ASU 2011-04”), Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is applied prospectively. ASU 2011-04 was made effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. The Company believes that the adoption of this standard did not materially expand the condensed consolidated financial statement footnote disclosures.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

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Note 3—Acquisitions

January 2012 Acquisition

On January 10, 2012, (“Closing Date”) the Company acquired two separate private, unaffiliated oil and gas company’s (“Sellers”) interests in approximately 50,000 net acres of Williston Basin leaseholds, and related producing properties located primarily in McKenzie and Williams Counties, North Dakota along with various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract (the “January 2012 Acquired Properties”) for a combination of cash and stock. The Seller received 5.1 million shares of Kodiak’s common stock valued at approximately $49.8 million and cash consideration of approximately $588.4 million. The effective date for the acquisition was September 1, 2011, with purchase price adjustments calculated at the Closing Date. The acquisition provided strategic additions adjacent to the Company’s core project area.  The January 2012 Acquired Properties contributed revenue of $13.8 million to Kodiak for the three months ended March 31, 2012.  Total transaction costs related to the acquisition were approximately $295,000, of which $85,000 and $0 were recorded in the statement of operations within the general and administrative expenses line item for the three months ended March 31, 2012 and 2011, respectively.  No material costs were incurred for the issuance of the 5.1 million shares of common stock.

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 January 10, 2012. 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, which may be material, as the Company continues to evaluate the fair value of the acquisition (in thousands):

	January 10, 2012
Preliminary Purchase Price
Consideration Given
Cash from Senior Notes	$	588,420
Kodiak Oil & Gas Corp. Common Stock (5,055,612 Shares)	49,798		*
Total consideration given	$	638,218
Preliminary Allocation of Purchase Price
Proved oil and gas properties	$	297,090
Unproved oil and gas properties	317,253
Wells in progress	25,745
Equipment and facilities	7,025
Total fair value of oil and gas properties acquired	647,113
Working capital	(8,095		)
Asset retirement obligation	(800		)
Fair value of net assets acquired	$	638,218
Working capital acquired was estimated as follows:
Accounts receivable	$	8,000
Prepaid completion costs	465
Crude oil inventory	540
Accrued liabilities	(12,400		)
Suspense payable	(4,700		)
Total working capital	$	(8,095	)

*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 January 10, 2012. (5,055,612 × $9.85)

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October 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. The October 2011 Acquired Properties contributed revenue of $13.8 million to Kodiak for the three months ended March 31, 2012. Total transaction costs related to the acquisition incurred were approximately $200,000.  Transaction costs are recorded in the statement of operations within the general and administrative expenses line item.  No transaction costs for the October 2011 Acquired Properties were recorded within the three months ended March 31, 2012 and 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. In February 2012, the Company completed the transactions post-closing settlement. 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):

	October 28, 2011
Preliminary Purchase Price
Consideration Given
Cash	$	248,213
Total consideration given	$	248,213
Preliminary Allocation of Purchase Price
Proved oil and gas properties	$	124,018
Unproved oil and gas properties	90,161
Wells in progress	25,720
Total fair value of oil and gas properties acquired	239,899
Working capital	8,552
Asset retirement obligation	(238		)
Fair value of net assets acquired	$	248,213
Working capital acquired was estimated as follows:
Accounts receivable	$	10,260
Prepaid drilling costs	755
Crude oil inventory	190
Well equipment inventory	1,324
Accrued liabilities	(1,247		)
Suspense payable	(2,730		)
Total working capital	$	8,552

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June 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 $14.4 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 $436,000 to Kodiak for the three months ended March 31, 2012.  Total transaction costs related to the acquisition were approximately $265,000.  Transaction costs are recorded in the statement of operations within the general and administrative expenses line item.  No transaction costs for the June 2011 Acquired Properties were recorded within the three months ended March 31, 2012 and 2011. 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 common stock.

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.  Of the $85.9 million purchase price, $8.0 million was allocated to proved oil and gas properties, $77.8 million was allocated to unproved oil and gas properties and the remaining $100,000 was working capital and asset retirement obligation adjustments.

Pro Forma Financial Information

The following unaudited pro forma financial information represents the combined results for the Company and the January 2012 Acquired Properties, October 2011 Acquired Properties and June 2011 Acquired Properties for the three months ended March 31, 2012 and 2011 as if the acquisitions had occurred on January 1, 2011 (in thousands, except per share data). For purposes of the pro forma it was assumed that the 8.125% Senior Notes were issued on January 1, 2011 and that the stand-by bridge was not utilized. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $600,000 and $3.6 million and amortization of financing costs of $0 and $400,000 for the three months ended March 31, 2012 and 2011, respectively. For the three months ended March 31, 2012, there was a pro forma adjustment of $400,000 reducing interest expense. For the three months ended March 31, 2011, there was no pro forma adjustment for interest expense. The pro forma financial information includes total capitalization of interest expense of $12.9 million and $14.3 million for the three months ended March 31, 2012 and 2011, respectively. The pro forma results do not include any cost savings or other synergies that may result from the acquisitions 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 acquisitions had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	Three Months Ended March 31,
	2012		2011
Operating revenues	$	81,736	$	21,131
Net income (loss)	$	2,969	$	(5,428	)
Net income (loss) per common share
Basic	$	0.01	$	(0.03	)
Diluted	$	0.01	$	(0.03	)

Note 4—Long-Term Debt

As of the dates indicated, the Company’s long-term debt consisted of the following (in thousands):

	March 31, 2012		December 31, 2011
Credit facility due October 2016	$	—	$	—
Second lien credit agreement due April 2017	—		100,000
8.125% Senior Notes due December 2019	650,000		650,000
Total Long-Term Debt	$	650,000	$	750,000
Less: Current Portion of Long Term Debt	—		—
Total Long-Term Debt, Net of Current Portion	$	650,000	$	750,000

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Credit Facility

Kodiak Oil & Gas (USA) Inc. (the “Borrower”), a wholly-owned subsidiary of Kodiak Oil & Gas Corp., has in place a credit agreement (“credit facility”) with a syndicate of banks.  The maximum credit available under the credit facility is $750.0 million with a current borrowing base of $225.0 million. Redetermination of the borrowing base 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. The credit facility matures on 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. The Applicable Margin for the ABR loans is a sliding scale of 0.75% to 1.75%, depending on borrowing base usage. The Applicable Margin on the adjusted LIBO rate is a sliding scale of 1.75% to 2.75%, depending on borrowing base usage. Additionally, the credit facility provides for a borrowing base fee of 0.5% and a commitment fee of 0.375% to 0.50%, 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 March 31, 2012 and the date of this filing:

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 credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants.  Additionally, the credit facility requires the Borrower to enter hedging agreements necessary to support the borrowing base.

The credit facility also contains financial covenants 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 to maintain, on the last day of each quarter, a ratio of total debt to EBITDAX of not greater than (i) 4.75 to 1.0 at the end of each of the two fiscal quarters ending December 31, 2011 and March 31, 2012, (ii) 4.50 to 1.0 at the end of the fiscal quarter ending June 30, 2012, (iii) 4.25 to 1.0 at the end of the fiscal quarter ending September 30, 2012, and (iv) 4.0 to 1.0 at the end of each fiscal quarter thereafter.  As of March 31, 2012, the Company was in compliance with all financial covenants under the credit facility.

As of March 31, 2012, the Company had no outstanding borrowings under the credit facility and as such, the available credit under the credit facility at that date was $225.0 million. Subsequent to March 31, 2012, the Company borrowed $30.0 million which is currently outstanding. Any borrowings under the credit facility are 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. The Company has entered into crude oil hedging transactions with Wells Fargo. The Company’s obligations under the hedging contracts with Wells Fargo are secured by the credit facility.

Second Lien Credit Agreement

On January 10, 2012, the Company terminated the second lien credit agreement and repaid the $100.0 million of outstanding debt, and incurred a $3.0 million prepayment penalty in connection therewith. The Company recorded the $3.0 million prepayment penalty in the first quarter of 2012 within the interest income (expense), net line item of the statement of operations.

Senior Notes

On November 23, 2011, the Company issued at par $650.0 million of 8.125% Senior Notes due December 1, 2019 (the “Senior Notes”). The interest on the Senior Notes is payable on June and December 1 of each year, beginning June 1, 2012. The proceeds received from the offer and sale of the Senior Notes were deposited into an escrow account, along with cash of the Company, in an amount equal to 101% of the offering price of the Senior Notes and the interest payable on the Senior Notes to March 22, 2012.  At December 31, 2011, there was $674.0 million in cash held in escrow related to the Senior Notes. As discussed in Note 3—Acquisitions, in January 2012, the Company completed the acquisition of the January 2012

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Acquired Properties and all funds were released from escrow. The Senior Notes were issued under an Indenture, dated as of November 23, 2011 (the “Indenture”) among the Company, Kodiak Oil & Gas (USA) Inc. (the “Guarantor”), U.S. Bank National Association, as the trustee (the “Trustee”) and Computershare Trust Company of Canada, as the Canadian trustee. The Indenture contains affirmative and negative covenants that, among other things, limit the Company’s and the Guarantor’s ability to make investments; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; pay dividends or make other distributions on capital stock or prepay subordinated indebtedness; and create unrestricted subsidiaries. The Indenture also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the Trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under its Senior Notes as of December 31, 2011, and through the filing of this report.

The Senior Notes are redeemable by the Company at any time on or after December 1, 2015, at the redemption prices set forth in the Indenture. The Senior Notes are redeemable by the Company prior to December 1, 2015, at the redemption prices plus a “make-whole” premium set forth in the Indenture. The Company is also entitled to redeem up to 35% of the aggregate principal amount of the Senior Notes before December 1, 2014 with net proceeds that the Company raises in equity offerings at a redemption price equal to 108.125% of the principal amount of the Senior Notes being redeemed, plus accrued and unpaid interest. If the Company undergoes a change of control on or prior to January 1, 2013, it may redeem all, but not less than all, of the Senior Notes at a redemption price equal to 110% of the principal amount of the Senior Notes redeemed plus accrued and unpaid interest. The Company estimates that the fair value of this option is immaterial at March 31, 2012.

The Senior Notes are jointly and severally guaranteed on a senior basis by the Guarantor and by certain of the Company’s future subsidiaries. The Senior Notes and the guarantees thereof will be the Company and the Guarantor’s general senior obligations and will, prior to the release of the amounts held in escrow, be secured by the net proceeds of the Company’s offer and sale of the Senior Notes and certain other funds held in the escrow account pursuant to an escrow agreement (upon release of such escrow property, the Senior Notes will not be secured), rank senior in right of payment to any of the Company’s and the Guarantor’s future subordinated indebtedness, rank equal in right of payment with any of the Company’s and the Guarantor’s existing and future senior indebtedness, rank effectively junior in right of payment to the Company’s and the Guarantor’s existing and future secured indebtedness (including indebtedness under the Company’s credit facility), to the extent of the value of the Company’s and the Guarantor’s assets constituting collateral securing such indebtedness, and rank effectively junior in right of payment to any indebtedness or liabilities of any the Company’s future subsidiaries of any subsidiary that does not guarantee the Senior Notes.

In connection with the sale of the Senior Notes, the Company entered into a registration rights agreement that provides the holders of the Senior Notes certain rights relating to the registration of the Senior Notes under the Securities Act. Pursuant to the registration rights agreement, the Company agreed to conduct a registered exchange offer for the Senior Notes or cause to become effective a shelf registration statement providing for the resale of the Senior Notes, each in accordance with the terms of the agreement. If the Company fails to comply with certain obligations under the agreement, it will be required to pay liquidated damages by way of additional interest on the Senior Notes.

Deferred Financing Costs

As of March 31, 2012, the Company had deferred financing costs of $21.4 million related to its credit facility and Senior Notes. Deferred financing costs include origination, legal, engineering, and other fees incurred in connection with the Company’s credit facilities and Senior Notes. For the three months ended March 31, 2012 and 2011, the Company recorded amortization expense of the deferred financing costs of $640,000 and $187,000, respectively.

Interest Incurred On Long-Term Debt

For the three months ended March 31, 2012 and 2011, the Company incurred interest expense on long-term debt of $13.5 million and $1.1 million, respectively. Of the total interest incurred, the Company capitalized interest costs of $12.5 million and $1.1 million for the three months ended March 31, 2012 and 2011, respectively.

11

Note 5— 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. A swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price.  A collar requires us to pay the counterparty if the settlement price is above the ceiling price and requires the counterparty to pay us if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The 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 three counterparties. 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 instruments are measured at fair value and are included in the accompanying balance sheets as commodity price risk management assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. 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. The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

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The Company’s commodity derivative contracts as of March 31, 2012 are summarized below:

Contract Type	Counterparty	Basis(1)	Quantity(B bl/d)	Strike Price ($/Bbl)	Term
Collar	Wells Fargo Bank, N.A.	NYMEX	400	$70.00/$95.56	Apr 1, 2012—Dec 31, 2012
Collar	Wells Fargo Bank, N.A.	NYMEX	230	$85.00/$117.73	Apr 1, 2012—Dec 31, 2012
Collar	Shell Trading (U.S.)	NYMEX	500	$85.00 - $117.00	Apr 1, 2012—Dec 31, 2013
Collar	Wells Fargo Bank, N.A.	NYMEX	300 - 425	$85.00 - $102.75	Jan 1, 2013—Dec 31, 2015

Contract Type	Counterparty	Basis(1)	Quantity(B bl/d)	Strike Price ($/Bbl)	Term
Swap	Wells Fargo Bank, N.A.	NYMEX	100	$84.00	Apr 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	136	$88.30	Apr 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	24	$90.28	Apr 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$85.00	Apr 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$85.07	Apr 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$102.05	Apr 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$107.20	Apr 1, 2012—Dec 31, 2012
Swap	Shell Trading (U.S.)	NYMEX	250	$85.01	Apr 1, 2012—Dec 31, 2012
Swap	Shell Trading (U.S.)	NYMEX	2,000	$96.88	Apr 1, 2012—Dec 31, 2012
Swap	Credit Suisse International	NYMEX	500	$106.85	Apr 1, 2012—Dec 31, 2012
Swap	Credit Suisse International	NYMEX	500	$107.25	Apr 1, 2012—Dec 31, 2012
2012 Total/Average			6,510	$96.45
Swap	Wells Fargo Bank, N.A.	NYMEX	79	$84.00	Jan 1, 2013—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	427	$88.30	Jan 1, 2013—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	24	$90.28	Jan 1, 2013—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$85.00	Jan 1, 2013—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	400	$85.07	Jan 1, 2013—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	425	$93.20	Jan 1, 2013—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$104.13	Jan 1, 2013—Dec 31, 2013
Swap	Shell Trading (U.S.)	NYMEX	250	$85.01	Jan 1, 2013—Dec 31, 2013
2013 Total/Average			3,105	$92.76
Swap	Wells Fargo Bank, N.A.	NYMEX	69	$84.00	Jan 1, 2014—Dec 31, 2014
Swap	Wells Fargo Bank, N.A.	NYMEX	360	$88.30	Jan 1, 2014—Dec 31, 2014
Swap	Wells Fargo Bank, N.A.	NYMEX	21	$90.28	Jan 1, 2014—Dec 31, 2014
Swap	Wells Fargo Bank, N.A.	NYMEX	350	$93.20	Jan 1, 2014—Dec 31, 2014
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$85.07	Jan 1, 2014—Dec 31, 2014
Swap	Credit Suisse International	NYMEX	1,000	$100.05	Jan 1, 2014—Dec 31, 2014
2014 Total/Average			2,800	$91.86
Swap	Wells Fargo Bank, N.A.	NYMEX	59	$84.00	Jan 1, 2015—Oct 31, 2015
Swap	Wells Fargo Bank, N.A.	NYMEX	317	$88.30	Jan 1, 2015—Sept 30, 2015
Swap	Wells Fargo Bank, N.A.	NYMEX	46	$90.28	Jan 1, 2015—Oct 31, 2015
Swap	Wells Fargo Bank, N.A.	NYMEX	300	$93.20	Jan 1, 2015—Dec 31, 2015
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$85.07	Jan 1, 2015—Dec 31, 2015
2015 Total/Average			1,625	$87.13

Subsequent to March 31, 2012, the Company entered into additional commodity derivative contracts as summarized below:

Contract Type	Counterparty	Basis(1)	Quantity(B bl/d)	Swap Price ($/Bbl)	Term
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$102.88	May 1, 2012 - Dec 31, 2012
Swap	Shell Trading (U.S.)	NYMEX	500	$102.85	May 1, 2012 - Dec 31, 2012
Swap	Credit Suisse International	NYMEX	1,000	$102.83	May 1, 2012 - Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$101.55	Jan 1, 2013 - Dec 31, 2013
Swap	Shell Trading (U.S.)	NYMEX	500	$101.32	Jan 1, 2013 - Dec 31, 2013
Swap	Credit Suisse International	NYMEX	1,000	$101.60	Jan 1, 2013 - Dec 31, 2013

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

13

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 March 31, 2012		As of December 31, 2011
Crude oil derivative contract	Current assets	$	688	$	—
Crude oil derivative contract	Noncurrent assets	$	426	$	—
Crude oil derivative contract	Current liabilities	$	20,220	$	11,925
Crude oil derivative contract	Noncurrent liabilities	$	21,470	$	10,035

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

	Three Months Ended March 31,
	2012			2011
Unrealized loss on oil contracts	$	(18,616	)	$	(9,350	)
Realized loss on oil contracts	(4,724		)	(342		)
Loss on commodity price risk management activities	$	(23,340	)	$	(9,692	)

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 6—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 Three Months Ended March 31, 2012			For the Year Ended December 31, 2011
	($ in thousands)
Balance beginning of period	$	3,627		$	1,968
Liabilities incurred or acquired	1,220			1,655
Liabilities settled	(42		)	(610		)
Revisions in estimated cash flows	—			418
Accretion expense	170			196
Balance end of period	$	4,975		$	3,627

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Note 7—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 significant assets or liabilities that were measured at fair value on a non-recurring basis in periods after initial recognition.

The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 6 - Asset Retirement Obligations, and the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 3 - Acquisitions.

The Company determines the estimated fair value of its asset retirement obligations at by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using level 3 inputs. 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 depleted as a component of the full cost pool using the units-of-production method.

The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at March 31, 2012 Using
	Level 1		Level 2			Level 3		Total
Financial Assets:
Commodity price risk management liability	$	—	$	1,114		$	—	$	1,114
Financial Liabilities:
Commodity price risk management liability	$	—	$	(41,690	)	$	—	$	(41,690	)

The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above:

Commodity Derivative Instruments

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. 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 March 31, 2012 and December 31, 2011, derivative instruments utilized by the Company consist of both “no premium” 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.

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Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents and accounts receivable, accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair value of the second lien credit agreement at December 31, 2011 was based on the amount paid on January 10, 2012 to extinguish the debt. The fair value of the Senior Notes was derived from available market data (level 2 inputs). This disclosure (in thousands) does not impact our financial position, results of operations or cash flows.

	At March 31, 2012				At December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Second Lien Credit Agreement	$	—	$	—	$	100,000	$	103,000
8.125% Senior Notes	$	650,000	$	687,375	$	650,000	$	656,500

Note 8—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 on June 15, 2011. The Plan authorizes the Company to issue stock options, stock appreciation rights, 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.

Stock Options

Total compensation expense related to the stock options of $1.4 million and $1.3 million was recognized for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, there was $8.4 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted-average period of 1.90 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:

16

	For the Three Months Ended March 31, 2012		For the Year Ended December 31, 2011
Risk free rates	0.99-1.48%		1.06 - 2.57%
Dividend yield	0%		0%
Expected volatility	89.08 - 90.25%		90.43 - 94.97%
Weighted average expected stock option life	5.63 years		6.01 years
The weighted average fair value at the date of grant for stock options granted is as follows:
Weighted average fair value per share	$	7.11	$	5.10
Total options granted	445,500		1,712,500
Total weighted average fair value of options granted	$	3,167,505	$	8,733,750

A summary of the stock options outstanding as of January 1, 2012 and March 31, 2012 is as follows:

			Weighted
			Average
	Number of		Exercise
	Options		Price
Balance outstanding at January 1, 2012	6,591,158		$	3.77
Granted	445,500		9.83
Canceled	(195,500	)	5.49
Exercised	(457,618	)	2.42
Balance outstanding at March 31, 2012	6,383,540		$	4.24
Options exercisable at March 31, 2012	4,007,040		$	2.92

At March 31, 2012, stock options outstanding were as follows:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Options Outstanding	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price		Number of Options Exercisable	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price
$0.36-$1.00	309,000	5.7	$	0.36	309,000	5.7	$	0.36
$1.01-$2.00	895,917	2.1	$	1.18	895,917	2.1	$	1.18
$2.01-$3.00	926,870	7.3	$	2.36	625,870	6.9	$	2.32
$3.01-$4.00	1,798,753	4.4	$	3.47	1,622,753	4.1	$	3.47
$4.01-$5.00	155,000	9.0	$	4.47	25,000	8.6	$	4.26
$5.01-$6.00	293,000	9.1	$	5.50	25,000	8.7	$	5.44
$6.01-$7.00	1,140,500	7.8	$	6.41	488,000	6.2	$	6.38
$7.01-$8.00	115,000	9.2	$	7.20	16,000	8.9	$	7.20
$8.01-$9.00	259,000	9.7	$	8.72	—	—	$	—
$9.01-$10.53	490,500	9.8	$	9.75	—	—	$	—
	6,383,540	6.2	$	4.26	4,007,540	4.5	$	2.92

The aggregate intrinsic value of both outstanding and vested options as of March 31, 2012 was $36.5 million based on the Company’s March 31, 2012 closing common stock price of $9.96 per share. The total grant date fair value of the shares vested during 2012 was $1.6 million.

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Restricted Stock Units and Restricted Stock

Total compensation expense related to restricted stock units (“RSUs”) and restricted stock of $1.0 million and $237,000 was recognized for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, there was $6.4 million of total unrecognized compensation cost related to the RSUs and restricted stock, which is expected to be amortized over a weighted-average period of 2.21 years.

In the fourth quarter 2011, the Company awarded 775,611 performance based RSUs to officers pursuant to the Company’s 2007 Plan. Subject to the satisfaction of certain 2012 performance-based conditions, the RSUs vest one-quarter per year over a four year service period and the Company began recognizing compensation expense related to these grants beginning in the fourth quarter 2011 over the vesting period. The Company recognizes compensation cost for performance based grants on a tranche level basis over the requisite service period for the entire award. The fair value of RSU’s granted is based on the stock price on the grant date and the Company assumed no annual forfeiture rate.

In the first quarter of 2012, the Company awarded grants of 30,000 shares of restricted stock to its Board of Directors pursuant to the Company’s 2007 Plan.  These restricted stock shares vest over a four year period and the Company began recognizing compensation expense related to these grants in the first quarter of 2012. The Company recognizes compensation cost for these grants on a straight-line basis over the requisite service period for the entire award. The fair value of restricted stock is based on the stock price on the grant date and the Company assumes a 3% annual forfeiture rate.

As of March 31, 2012, there were 985,611 unvested RSUs and 30,000 unvested restricted stock shares with a combined weighted average grant date fair value of $8.55 per share. The total fair value vested during the three months ended March 31, 2012, was $166,000. A summary of the RSUs and restricted stock shares outstanding is as follows:

			Weighted
			Average
	Number of		Grant Date
	Shares		Fair Value
Non-vested restricted stock at January 1, 2012	1,008,111		$	8.48
Granted	30,000		9.87
Forfeited	—		—
Vested	(22,500	)	7.39
Non-vested restricted stock at March 31, 2012	1,015,611		$	8.55

Note 9—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 8—Share-Based Payments under the heading Restricted Stock Units and Restricted Stock for additional discussion.

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The table below sets forth the computations of basic and diluted net income (loss) per share for the three months ended March 31, 2012 and 2011 (in thousands, except per share data):

	For the Three Months Ended March 31,
	2012			2011
Basic net income (loss)	$	1,744		$	(7,235	)
Income allocable to participating securities	(1		)	—
Diluted net income (loss)	$	1,743		$	(7,235	)
Basic weighted average common shares outstanding	262,660,642			178,451,574
Effect of dilutive securities
Options to purchase common shares	5,978,040			—
Assumed treasury shares purchased	(2,372,171		)	—
Unvested restricted stock units	319,505			—
Diluted weighted average common shares outstanding	266,586,016			178,451,574
Basic net income (loss) per share	$	0.01		$	(0.04	)
Diluted net income (loss) per share	$	0.01		$	(0.04	)

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 March 31,
	2012	2011
Anti-dilutive shares	405,500	652,000

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 $2.8 million at March 31, 2012.  The future minimum lease payments under these non-cancelable leases are as follows: $440,000 in 2012, $600,000 in 2013, $600,000 in 2014, $625,000 in 2015, and $540,000 in 2016.

Drilling Rigs

As of March 31, 2012 the Company was subject to commitments on six drilling rig contracts. One of the contracts expires in 2012, four expire in 2013 and one expires in 2015. In the event of early termination under all of these contracts, the Company would be obligated to pay an aggregate amount of approximately $60.9 million as of March 31, 2012 as required under the varying terms of such contracts.

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Pressure Pumping Services

As of March 31, 2012, the Company was subject to a commitment with a pressure-pumping service company providing 24-hour per day frac crew availability for 30 days per month, to be reconciled on a quarterly basis.  In the event of early contract termination, the Company would be obligated to pay approximately $36.0 million as of March 31, 2012 as required under the terms of the contract.

Guarantees

In November 2011, the Company issued $650.0 million of Senior Notes due in 2019 which are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. Kodiak Oil & Gas Corp, as the parent company, has no independent assets or operations. The guarantee is full and unconditional, and the parent company has no other subsidiaries. In addition, there are no restrictions on the ability of the parent company to obtain funds from its subsidiary by dividend or loan. Finally, the parent company’s wholly-owned subsidiary does not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the parent company in the form of loans, advances or cash dividends by the subsidiary without the consent of a third-party.

The Company may issue additional 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. As stated above, the Company has no independent assets or operations nor does it have any other subsidiaries, and 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.

Other

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

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

Forward-Looking Statements

The information discussed in this quarterly report 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:

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

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

·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;

·geographical concentration of our 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;

·termination fees related to drilling rig contracts and pressure pumping service contract;

·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;

·adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;

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

·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;

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·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;

·constraints in the Williston Basin with respect to gathering, transportation and processing facilities and marketing;

·federal, state and tribal regulations and laws;

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

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

·federal and state legislation and regulatory initiatives relating to hydraulic fracturing;

·integration of significant acquisitions, and difficulty managing our growth and the related demands on our resources;

·developments in the global economy;

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

·financing and interest rate exposure;

·effects of competition;

·effect of seasonal factors;

·lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oil field services; and

·further sales or issuances of common stock.

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. We have developed an oil and natural gas asset base of proved reserves, as well as a portfolio of development and exploratory opportunities on high-potential prospects with an emphasis on oil resource plays.  Our oil and natural gas reserves and operations are primarily concentrated in the Williston Basin of North Dakota and to a lesser extent the Greater Green River Basin of Wyoming.  As of March 31, 2012, we owned an interest in approximately 238,000 gross (157,000 net) acres in the Williston Basin where our primary target is the middle Bakken and Three Forks formations.

Since late 2010 through the first quarter of 2012, we have added significantly to our asset base in the Williston Basin through targeted acquisitions of properties within our core operating area.  We intend to expand our asset base by drilling and completing wells on our current lands, and we will continue to evaluate and invest in acquisitions, if and to the extent opportunities arise.

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As of the date of this filing, we operate six drilling rigs on our acreage, and we have a seventh rig under contract for delivery in the second quarter of 2012.  The Company also has a full-time, 24-hour-per-day completion crew that commenced work on our behalf at the beginning of the year.  We intend to utilize a second completion crew in order to accelerate completion activity.  In addition, our partner in an area of mutual interest is currently operating two rigs.  We have an approximate 50% ownership in this area of mutual interest.  As of April 2012, we have an interest in 160 gross (65.9 net) producing wells in the Williston Basin.

Recent Developments

Operational Update

During the first quarter 2012, we focused on integrating our October 2011 and January 2012 property acquisitions into our operations.  Due to a shortage of workover rigs in late 2011 and early 2012, we encountered delays while installing artificial lift on some of the wells.  The result was that these wells were shut in during those time periods, but were returned to production in mid-February.  In addition, during the first quarter of 2012, additional completion procedures were required on several of the wellbores acquired in our October 2011 and January 2012 property acquisitions to bring the wells on to production.

During the first quarter of 2012, we continued our repair and remediation work on wells that encountered mechanical issues during completion procedures during the end of 2011 and in early 2012. We successfully repaired two wells, one of which has been completed in the sleeve stages and flowed back at a rate of 765 BOE/d from five stages.  The remaining plug and perforation stages will be completed at a later date.  The second well is currently scheduled for completion in the second quarter of 2012.  Ultimately, we expect all of the wells to be remediated and undergo completion operations.  We now anticipate the wells coming on-line during the last three quarters of 2012.  We have addressed these mechanical issues predominantly through the use of cemented liners in new wells being drilled, which we believe reduces our risk of mechanical failures.

In the first quarter of 2012, we focused on delineating our acreage in the more outlying areas by drilling the Grizzly and Charging Eagle wells.  We are very pleased with the four gross (2.3 net) Charging Eagle wells completed in the very southeastern portion of Dunn County, one of which was a Three Forks test.  We also completed three gross (2.5 net) wells in our Grizzly project area in southwest McKenzie County that is characterized by lower reservoir pressures which do not yield the robust initial production rates common in other parts of the Basin. Further details of these wells are shown in the summary drilling and completion schedule below.  For the remainder of the year, we expect all of our operated wells to be drilled and completed through the heart of our core leasehold in southern Williams, McKenzie and Dunn counties, where we carry a high working interest in the wells.

Overall, during the first quarter of 2012, we drilled 14 gross (12.1 net) operated wells and completed 12 gross (8.0 net) operated wells.  As of March 31, 2012 Kodiak had 14 gross (12.6 net) operated wells drilled and waiting to be completed.  Completion operations have recently finished on two gross (1.9 net) operated wells in April that are now flowing back.  The Company expects an additional 12 gross (10.7 net) operated wells to be completed during the remainder of the second quarter of 2012.

Furthermore, the Company participated in the drilling of 21 gross (3.9 net) non-operated wells and the completion of nine gross (2.1 net) non-operated well during the first quarter of 2012.  As of March 31, 2012 the Company has an interest in 16 gross (3.3 net) non-operated wells that are waiting on completion.

Overall, we anticipate that our drilling and well completion efforts will continue on pace the remainder of 2012 with a total of 73 gross (51.0 net) operated wells projected to be completed by year-end.

Generally, in the Williston Basin, oil, gas and water infrastructure 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 first quarter and will continue to expand into 2012.  In McKenzie and Williams counties, 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.  To date, we have drilled the first of three expected water disposal wells on our acreage.  With the addition of these wells and future water gathering systems, we anticipate that our operating costs, on a per unit basis, will improve.

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The following summary provides a tabular presentation of our completion activities during the first quarter of 2012:

Kodiak Oil & Gas Corp.

Q1 2012 Bakken and Three Forks Completion Activities

				Production Volumes (BOE/d)
	WI / NRI		Length of	IP 24 Hour	30 Day	60 Day
Well Name	(%)	Formation	Lateral	Test	Cum	Cum
Dunn County, ND
Skunk Creek 2-8-17-14H3	44 / 38	Three Forks	9,354’	2,680	1,277	1,048
Skunk Creek 9-2-3-5H	99 / 81	Bakken	9,240’	2,174	912	—
Charging Eagle 15-14-11-4H	60 / 49	Bakken	9,209’	2,429	921	—
Charging Eagle 15-14-24-16H	60 / 49	Bakken	8,695’	1,716	646	—
Williams and McKenzie Counties, ND
Grizzly 149-104-15-12-1-2H	78 / 64	Bakken	8,632’	1,026	—	—
Grizzly 3-25-13-3H	86 / 71	Bakken	10,075’	508	—	—
Grizzly 3-25-36-15H	90 / 74	Bakken	9,407’	689	401	—
Pankowski 4-6H	61 / 49	Three Forks	8,860’	1,588	—	—
Long 112-1H	73 / 56	Bakken	9,583’	1,978	1,017	908
Lind 211-1H	70 / 54	Bakken	9,563’	1,419	704	560
Mildred 94-1H	45 / 35	Bakken	10,041’	1,396	495	427
State 1621-1H	36 / 28	Bakken	8,926’	1,658	525	446
Non-Operated: Dunn County, ND
FBIR Darcie 34X-10 (1)	44 / 36	Bakken	9,494’	1,561	N/A	N/A
FBIR IronWoman 21X-10 (1)	50 / 41	Bakken	9,467’	2,355	N/A	N/A
FBIR WalterPacksWolf 31X-12	50 / 41	Bakken	9,217’	1,290	N/A	N/A
FBIR YellowWolf 21X-10	50 / 41	Bakken	9,720’	1,445	N/A	N/A
FBIR GuyBlackHawk 24X-27	50 / 41	Bakken	9,221’	Well on Confidental Status

(1) Wells completed in Q4 2011.

Closing on Acquisition of Williston Basin Properties

On January 10, 2012, we closed an acquisition of approximately 50,000 net oil and gas leasehold acres and producing properties located principally in Williams and McKenzie counties of North Dakota, and various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract (the “January 2012 Acquisition”). The effective date for this acquisition was September 1, 2011.

We closed this acquisition for aggregate consideration of approximately $638.2 million. This consideration was comprised of (i) 5,055,612 shares of the Company’s common stock and (ii) cash consideration in an amount equal to approximately $588.4 million. The purchase price included normal closing adjustments to reflect the effective date of the acquisition, which includes reimbursement to the seller in this transaction for operational expenditures during the timeframe between the effective date of the acquisition and the closing date. We funded the cash balance due at closing through the release from escrow of the proceeds from our November 2011 high yield debt offering.

Regulatory Matters

On April 17, 2012, the Environmental Protection Agency (“EPA”) issued final rules that subject oil and natural gas production, processing, transmission and storage operations within federal regulatory jurisdiction to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules include NSPS standards for completions of hydraulically fractured wells.

The final rules establish a phase-in period that will ensure that manufacturers have time to make and broadly distribute the required emissions reduction technology.  During the first phase, until January 1, 2015, owners and operators must either flare their emissions or use emissions reduction technology called “green completions,” technologies that are already widely deployed at wells.  The finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to the Company’s operations, including the installation of new equipment to control emissions. The Company is currently evaluating the effect these rules will have on its business.

Capital Resources and Liquidity

2012 Capital Expenditures Budget

Our 2012 capital expenditure budget of $585.0 million (exclusive of $647.1 million used to fund our January 2012 Acquisition) is subject to various factors, including market conditions, oilfield services and equipment availability, commodity prices and drilling results.  During the first three months of 2012, we invested capital expenditures of approximately $170.0 million related to drilling and completion operations, and related infrastructure and leasehold acquisition (exclusive of our January 2012 Acquisition).  Our 2012 capital expenditures budget is comprised of the following:

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·$575.0 million for the drilling and completion of 73 gross and (51.0 net wells) wells and related infrastructure. In the three month period ended March 31, 2012, we spent approximately $163.2 million on these activities (inclusive of capitalization of $12.5 million of interest). 

·$10.0 million for leasehold expenditures.  In the three month period ended March 31, 2012, we have purchased 1,680 gross (1,005 net) acres incurring approximately $6.8 million on leasehold expenditures.

Senior Notes

In November 2011, we issued at par $650.0 million of 8.125% Senior Notes due December 1, 2019, the proceeds of which were deposited into escrow. Upon closing the January 2012 Acquisition, the escrow related to the Senior Notes was released.  The escrow proceeds were primarily used to finance the January 2012 Acquisition and repay all borrowings under the second lien credit agreement. The interest on our Senior Notes is payable on June and December 1 of each year, beginning June 1, 2012. For further discussion regarding the Senior Notes, please refer to Note 4—Long-Term Debt under Item 1 in this Quarterly Report.

Derivative Instruments

We use various derivative instruments in connection with anticipated crude oil sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Currently, we utilize swaps and “no premium” collars. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments.

Working Capital

Our working capital was negative $56.9 million at March 31, 2012 and positive $81.8 million at March 31, 2011. We expect to maintain low cash and cash equivalent balances going forward because we use available funds to reduce our balance on our credit facility. Short-term liquidity needs are satisfied by borrowings under our credit facility. Because of this, and since our principal source of operating cash flows (proved reserves to be produced in future years) cannot be reported as working capital, we may have low or negative working capital.

Sources of Capital

Our 2012 drilling program is designed to provide flexibility in identifying suitable well locations and in the timing and size of capital investment. We anticipate funding this capital program and meeting our debt service requirements through our existing cash on hand, the increase in our operating cash flows, and additional credit that may be available through our borrowing base facility. We plan to finance the remaining $415.0 million of our $585.0 million 2012 capital expenditure budget utilizing the following sources of capital:

Cash flow from operations.  As discussed in more detail below, our net cash provided by operating activities has increased significantly for the three months ended March 31, 2012 as compared to the same period in 2011. This increase is directly related to our successful drilling and completion operations as we have developed our Bakken properties and the addition of producing properties through our acquisition activity. In addition to the increase in the number of wells on production, the per-well production has increased as we have enhanced our completion techniques with advanced fracture stimulations. Throughout 2012, we expect our cash flow from operations to continue to significantly increase commensurate with our increase in estimated production. If we are able to drill and complete our wells as anticipated and they produce at

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rates similar to those generated by our existing wells, we would expect our production rates and operating cash flows to grow significantly as we move through 2012. We estimate that our 2012 average daily sales volumes will be approximately 17,000 to 21,000 BOE per day as compared to approximately 4,000 BOE per day in 2011.

Credit Facility.  In November 2011, we amended our credit facility pursuant to which we increased our borrowing base to $225.0 million with a maximum credit amount of $750.0 million and a maturity date of November 14, 2016. This facility, as of March 31, 2012, had availability of $225.0 million.  Subsequent to March 31, 2012, we borrowed $30.0 million under this credit facility resulting in availability of $195.0 million as of the date of this filing. Redetermination of the borrowing base occurs semi-annually, on April 1 and October 1.  The borrowing base was reaffirmed as of April 1, 2012, and the Company expects to elect a borrowing base redetermination in order to increase the borrowing base during the second quarter of 2012.  The Company may elect a redetermination of the borrowing base one time during any six month period. The ability to maintain this facility and borrow additional funds is dependent on a number of variables, including our proved reserves, and assumptions regarding the price at which oil and natural gas can be sold. Further, we expect that our borrowing base will increase with the addition of proved properties as a result of our ongoing drilling and completion activities.  We are subject to restrictive covenants under the credit facility.  For further details on the credit facility please refer to Note 4—Long-Term Debt under Item 1 in this Quarterly Report.

If any of these sources were to be unavailable or insufficient to fund our 2012 drilling program, debt service requirements, other contractual obligations and our general and administrative expenses, we would need to secure other sources of funding, such as through the sales of our securities.  Historically, we have financed our operations, property acquisitions and other capital investments from the proceeds of offerings of our equity and debt securities. We currently have on file with the SEC a universal shelf registration statement to allow us to offer an indeterminate amount of securities in the future. Under the registration statement, we may offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

We expect that our cash flows from operations, our cash on hand and increases in our borrowing base, if necessary and available, will be sufficient to meet our remaining 2012 capital expenditures budget and to satisfy our 2012 obligations under our Senior Notes and other 2012 contractual commitments (please refer to Note 10 - Commitments and Contingencies under Item 1 in this Quarterly Report). If our existing and potential sources of liquidity were not to be sufficient to satisfy such commitments and to undertake our currently planned expenditures, we believe that we have the flexibility in our commitments to alter our drilling program.  Since we operate the majority of our acreage, we have the ability to adjust our drilling schedule to reflect the changing commodity price or oil field service environment.  Additionally, we believe the majority of our leasehold can be held by production even with a reduced number of drilling rigs, because much of our leasehold is either currently held by production or will be held by production in the near term. We may incur termination fees depending on the timing and contractual requirements of our drilling rig and completions services contracts. If necessary, we may conduct an offering of our securities.  There can be no assurance that any such transactions can be completed or that such transactions would satisfy our operating capital requirements and other commitments. If we were not successful in obtaining sufficient funding, we would be unable to implement our original exploration and drilling program, and we may be unable to service our debt obligations or satisfy our contractual obligations.

Cash Flow Analysis

Following is a summary of our change in cash and cash equivalents from March 31, 2011 to March 31, 2012:

	($ in thousands)
	Three Months Ended March 31,
	2012			2011			Period to period change
Net cash provided by operating activities	$	56,551		$	7,152		$	49,399
Net cash used in investing activities	(684,673		)	(33,125		)	(651,548		)
Net cash provided by financing activities	571,423			930			570,493
Decrease in cash and cash equivalents	$	(56,699	)	$	(25,043	)	(31,656		)

Net cash provided by operating activities.  The key components of our net cash provided by operating activities are our production volumes (in particular, our crude oil sales volumes) and commodity prices (in particular, crude oil prices). 

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For the first three months of 2012 as compared to the same period in 2011, our net cash provided by operating activities increased by $49.4 million, primarily from increased crude oil sales volumes attributable to our successful drilling and completions in our core Bakken and Three Forks formations in the Williston basin and, to a lesser extent, due to an increase in our accounts payable balance from year-end 2011.

Net cash used in investing activities.  The primary driver in our net cash used for investing activities is our capital expenditure budget, which consists of both our ongoing drilling and completion expenditures and our acquisition expenditures.  For the first three months of 2012 as compared to the same period in 2011, our net cash used in investing activities increased by $651.5 million.  This increase is primarily attributed to our January 2012 Acquisition, which required $588.4 million in cash, and secondarily, to our significantly increased capital expenditures for drilling and completions during the first quarter of 2012 as compared to the same period in 2011.

Net cash provided by financing activities.  For the first three months of 2012 as compared to the same period in 2011, our net cash provided by financing activities increased by $570.5 million.  This was a result of our receipt from escrow of $670.6 million, of which $588.4 million was used for closing our January 2012 Acquisition, and $100.0 million was used to repay our entire outstanding balance on our second lien credit agreement.

Our Properties

Williston Basin (157,000 net acres)

Our Williston Basin acreage is located primarily in Dunn, McKenzie and Williams Counties, of North Dakota. Our primary geologic target in the Williston Basin is the Bakken Pool. In the Bakken Pool, our primary objective is the dolomitic, sandy interval between the two Bakken Shales at an approximate vertical depth of 10,300-11,300 feet and the Three Forks Formation immediately below the lower Bakken Shale. The Williston Basin also produces from many other formations including, but not limited to, the Mission Canyon, Nisku and Red River.

We have focused our operations in an area that we believe has higher reservoir pressure, a high degree of thermal maturity, and is prospective for both the middle Bakken and the Three Forks formations. Based on recent drilling results, along with internal and third-party reserve engineering analysis, we expect wells in this area to have economic ultimate recoveries (“EUR’s”) that range from 450 to over 900 MBOE.

Other important aspects of our drilling program in this core Williston Basin area include the following:

·Based upon our exploration efforts from 2009 through early 2012, we believe that the internal rate of return of the longer 10,000 foot laterals is higher than we were achieving with our shorter laterals of 5,000 feet or less. Although utilizing long laterals is more expensive, we estimate that the additional costs of drilling the longer lateral and adding more fracture stimulation stages is offset by the associated incremental increase in oil production.

·We have continued to drill on pads with two to four wells. We believe that, in future years, the number of wells drilled from each pad could increase. The significance of pad drilling is primarily directed to mobilization and demobilization of our drilling rigs which reduces costs and minimizes the impact on the surface locations. As the industry is facing a shortage of services, the use of pad drilling has become even more important as it lowers the number of moves required between wells, eliminating the need for trucks to move the equipment, a service that is in tight demand. Furthermore, we have seen efficiencies in our completion work as we eliminate mobilization and demobilization time for our pressure pumping company allowing it more efficient use of its time. In 2012, we plan to drill all wells from two-well to four-well pads.

·We expect to drill future wells with the density of approximately 1,300 feet or less of horizontal separation. We have completed five sets of middle Bakken wells with separation of approximately 1,300 feet or less. With the data obtained during the stimulation procedures, we experienced very little communication between formations and we believe that this spacing can be used as we move to development. Based upon the thickness of the middle Bakken in our prospect areas, we believe the results of our completion work support a density of up to four middle Bakken wells within many of our drilling units.

·Completion techniques have been and will continue to be evaluated with the expectation of further enhancing our completion methods as more data becomes available. Early results from our completion of seven gross operated wells in the Three Forks Formation are similar to the results of our middle Bakken wells and indicative of the

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potential of the formation. Results have shown very little communication with the middle Bakken reservoir, suggesting separate reservoirs. All of these wells were positioned less than 700 feet horizontally from a middle Bakken well with approximately 65 feet of vertical separation. This work has continued to support our belief that potentially three to four Three Forks wells can be completed in a drilling unit below the middle Bakken wells.

·Our leasehold is largely contiguous and by virtue of our high working interest and operatorship, we can control the development pace and location of surface facilities. We believe this strategy, combined with pad drilling and long laterals, will maximize the efficiency of our drilling program and minimize the infrastructure required to connect our wells to sales pipelines. 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. Once all of our acreage is held by production, we expect to gain efficiencies as this will allow us to develop acreage in a more methodical approach.

·Most of our core Williston Basin area is served by third-party oil and gas gathering systems. The majority of our wells are connected to or are in the process of being connected to oil and gas pipelines. However, our gas sales continue to be limited by plant capacity needed to process the gas and strip out the high liquids content. Moving oil and gas through pipelines eliminates trucking costs and associated surface disturbance, and mitigates weather-related production interruptions. As the capacity of natural gas pipelines and related processing facilities increases, we should be able to capture additional revenue generated from the sale of associated natural gas that is currently flared.

·In Dunn County, we have progressed in connecting our wells to third-party pipelines that transport water directly to disposal facilities. In 2012, we are drilling water disposal wells on several of our producing areas outside of Dunn County and plan to construct water gathering systems where appropriate.

Our Leasehold

As of March 31, 2012, we had several hundred lease agreements representing approximately 272,400 gross and 168,400 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	25,821	5,889	1,700	953	27,521	6,842
Colorado	7,339	4,960	0	0	7,339	4,960
Williston Basin
Montana	2,359	1,240	3,240	2,446	5,599	3,686
North Dakota	132,650	87,462	99,275	65,450	231,925	152,912
Acreage Totals	168,169	99,551	104,215	68,849	272,384	168,400

(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 credit facility.

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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, 2012	24,543	13,953
December 31, 2013	36,855	19,891
December 31, 2014	13,972	14,966
December 31, 2015	12,044	5,355
Total	87,414	54,165

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, 2011, this field contained 99% of our total proved reserves, nearly all of which are located in Williams, 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 March 31,
	2012	2011
Sales Volume (Bakken):
Oil (Bbls)	874,156	149,749
Gas (Mcf)	493,592	21,630
Sales Volume (Other):
Oil (Bbls)	4,420	7,646
Gas (Mcf)	10,584	40,573
Sales Volume (Total):
Oil (Bbls)	878,576	157,395
Gas (Mcf)	504,176	62,203
Sales volumes (BOE)	962,606	167,762
Natural Gas flared (Mcf) (1):	637,047	88,292
Total production volume (Total):
Oil (Bbls)	888,324	157,395
Gas (Mcf)	1,141,223	150,495
Production volumes (BOE)	1,078,528	182,477

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

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Sales prices received, and production costs per sold BOE for the three months ended March 31, 2012 and 2011 are summarized in the following table:

	For the Three Months Ended March 31,
	2012			2011
Sales Price:
Oil ($/Bbls)	$	87.43		$	82.72
Gas ($/Mcf) (1)	$	6.19		$	5.04
Commodity Price Risk Management Activities ($/Sales BOE):
Realized loss	$	(4.91	)	$	(2.04	)
Production costs ($/Sales BOE):
Lease operating expenses	$	7.05		$	5.97
Production and property taxes	$	8.83		$	9.05
Gathering, transportation, marketing	$	2.09		$	0.33
DDA	$	27.32		$	22.18
G&A	$	8.20		$	28.12
Stock-based compensation	$	2.53		$	9.17

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

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

Oil sales revenues.  Oil sales revenues increased by $63.8 million to $76.8 million for the three months ended March 31, 2012, as compared to oil sales of $13.0 million for the same period in 2011. Our oil sales volume increased 458% or 721.2 thousand barrels (MBbls) to 878.6 MBbls in the first quarter of 2012 as compared to 157.4 MBbls in the first quarter of 2011. The average price we realized on the sale of our oil was $87.43 per barrel in the 2012 period compared to $82.72 per barrel in 2011. The volume increase is due to the development of our Bakken properties as well as the June 2011, October 2011 and January 2012 property acquisitions.  Of the 721.2 MBbls increase in sales volume, 310.4 MBbls is related to properties acquired in these acquisitions and 410.8 MBbls is attributed to our ongoing development of our legacy properties.  Overall, 99% of the increase in oil sales revenue was attributed to increased volumes and 1% was attributed to the increase in crude oil prices received.

Natural gas sales revenues.  Natural gas sales revenues increased by $2.8 million to $3.1 million for the three months ended March 31, 2012, as compared to natural gas sales revenues of $314,000 for the same period in 2011. Natural gas sales volumes increased to 504,200 Mcf in the first quarter of 2012 compared 62,200 Mcf in the same period in 2011. The average price we realized on the sale of our natural gas was $6.19 per Mcf in the 2012 period compared to $5.04 per Mcf in 2011.  Overall, 97% of the increase in natural gas sales revenue was attributed to increased volumes and 3% was attributed to the increase in natural gas prices received. The volume increase is due to the development of our Bakken properties as well as the June 2011, October 2011 and January 2012 acquisitions.  Of the 504,200 Mcf increase in sales volume, 219,200 Mcf is related to properties acquired in these acquisitions and 285,000 Mcf is attributed to our ongoing development of our legacy properties.  Although gas from certain Bakken wells continues to be flared, during 2011 and continuing into 2012, we connected the majority of our wells to gas pipelines which allowed us to capture the related sales revenue. Industry-wide in the Williston basin, there has continued to be a shortage of gas gathering and processing capacity which has limited our ability to sell our gas production. Throughout 2012, we expect to continue to connect to third-party gathering facilities.  As these third-parties expand their processing capacity we expect additional gas volumes to be gathered, processed and sold.

Oil and gas production expense.  Our oil and gas production expense increased by $14.7 million to $17.3 million for the quarter ended March 31, 2012 as compared to $2.6 million for the same period in 2011. The increase is due to a $7.0 million increase in production taxes, a $5.8 million increase in lease operating expenses (“LOE”) and a $1.9 million increase in gathering, transportation and marketing expense. 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 $5.97 per barrel sold in 2011 to $7.05 in 2012. The largest component of our lease operating expense continues to be the disposal of produced water.  To date, the majority of water has been transported by truck to third-party disposal facilities. During 2011 and continuing into 2012, we have progressed in connecting our wells to third-party pipelines where available. To further reduce water disposal costs, in 2012, we are drilling water disposal wells on several of our producing areas and constructing water gathering systems where appropriate. As we

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connect existing and future wells to these water gathering systems, we expect our LOE to decrease on a per unit basis.  Regarding the increase in gathering, transportation and marketing expense, as we connect our wells to both oil and gas pipelines, our gathering expenses will continue to increase.  However, this increase is offset by a decrease in our crude oil price differential due to the elimination of the trucking component in our net oil price.  Additionally, although we incur the gathering expense, we recognize the associated gas sales when our wells are connected to gathering and processing systems.

Depletion, depreciation, amortization and abandonment liability accretion (“DD&A”) expense.  Our depletion, depreciation, amortization and abandonment liability accretion expense increased by $22.6 million to $26.3 million for the three months ended March 31, 2012, from $3.7 million for the same period in 2011. This increase is due to increased volumes sold in 2012 as sales increased by approximately 794,800 BOE over the same period. On a per unit basis, DD&A increased from $22.18 per barrel sold in the first quarter of 2011 to $27.32 per barrel sold in 2012. This increase in DD&A rate was primarily the result of the allocation of the purchase price to proved properties related to our acquisitions in October 2011 and January 2012. Acquired proved reserves are valued at fair market value on the date of acquisition, which contributes to a higher amortization base, as compared to our historical cost of acquiring leasehold and developing our properties. To date, the fair value of our acquired proved reserves has been higher than our historical cost of developing our properties even though the resulting EUR’s are equivalent. Therefore, the increase in the ratio of costs subject to amortization to the reserves acquired is greater than our internally developed properties. We believe that, although initially these acquisitions increase our DD&A rate per BOE over the development of the acquired properties, the resulting rates will decline with infill drilling and the addition of the related reserves.

General and administrative (“G&A”) expense.  G&A expense increased by $3.2 million to $7.9 million for the quarter ended March 31, 2012, from $4.7 million for the same period in 2011. 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 74 at March 31, 2012, from 40 at March 31, 2011.

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 March 31, 2012, this expense was $2.4 million as compared to $1.5 million in 2011.

Operating income.  Our operating income was approximately $28.4 million for the quarter ended March 31, 2012, as compared to approximately $2.3 million for the quarter ended March 31, 2011. This increase in operating income is attributed to our recent acquisitions, our on-going successful completions of wells in our Bakken play as well as crude oil price improvement from the first quarter of 2011 to the first quarter of 2012.

Loss on commodity price risk management activities.  Primarily due to the increase in NYMEX crude oil prices during the first quarter of 2012, we incurred a total loss on our risk management activities of $23.3 million for the three months ended March 31, 2012 compared to $9.7 million for the comparable period in 2011. This loss is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. This loss was comprised of approximately $4.7 million of realized losses for transactions that were settled during the first quarter of 2012 and $18.6 million of unrealized losses for the mark-to-market of forward transactions. The unrealized loss is a non-cash adjustment for the value of our risk management transactions at March 31, 2012. These transactions will continue to change in value until the transactions are settled and we will likely add to our hedging program. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time.

Interest income (expense), net.  For the three months ended March 31, 2012, we recognized interest expense of approximately $4.6 million, as compared to interest income of $33,000 for the same period in 2011. Included in interest expense in 2012 was a $3.0 million prepayment penalty to terminate the second lien credit agreement.  We recognized interest expense and amortization of deferred financing costs for the three months ended March 31, 2012 of approximately $1.6 million related to the Senior Notes, credit facility and second lien credit agreement. Additionally, we capitalized interest costs of $12.5 million and $1.1 million for the three months ended March 31, 2012 and 2011, respectively.

Net income (loss).  Our net income was $1.7 million for the quarter ended March 31, 2012, as compared to a $7.2 million loss for the quarter ended March 31, 2011. Although our operating income was higher compared to 2011, our 2012 net income was negatively impacted by the unrealized loss on commodity price risk management activities as discussed above and, to a lesser extent, interest expense on debt incurred to finance our various acquisitions during 2011 and the first quarter of 2012.

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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 March 31, 2012 and December 31, 2011.

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. 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. A summary of the Company’s significant accounting policies is included in Note 2 to the Company’s consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2011, as well as in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in such Form 10-K.  There have been no significant changes in the Company’s application of its critical accounting policies during the first three months of 2012.

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 continued throughout 2011 and early 2012. 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 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.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our primary market risk is the volatility of 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 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.

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.

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 three 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 March 31, 2012 are summarized below:

Collars	Quantity (Bbl/d)	Strike Price ($/Bbl)
Apr 1, 2012—Dec 31, 2012	400	$	70.00 - $95.56
Apr 1, 2012—Dec 31, 2012	230	$	85.00 - $117.73
Apr 1, 2012—Dec 31, 2013	500	$	85.00 - $117.00
Jan 1, 2013—Dec 31, 2015	300 - 425	$	85.00 - $102.75

Swaps	Quantity (Bbl/d)	Swap Price ($/Bbl)
2012 Total/Average	6,510	$	96.45
2013 Total/Average	3,105	$	92.76
2014 Total/Average	2,800	$	91.86
2015 Total/Average	1,625	$	87.13

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Subsequent to March 31, 2012, the Company entered into additional commodity derivative contracts as summarized below:

Contract Type	Counterparty	Basis(1)	Quantity(B bl/d)	Swap Price ($/Bbl)		Term
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$	102.88	May 1, 2012 - Dec 31, 2012
Swap	Shell Trading (U.S.)	NYMEX	500	$	102.85	May 1, 2012 - Dec 31, 2012
Swap	Credit Suisse International	NYMEX	1,000	$	102.83	May 1, 2012 - Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$	101.55	Jan 1, 2013 - Dec 31, 2013
Swap	Shell Trading (U.S.)	NYMEX	500	$	101.32	Jan 1, 2013 - Dec 31, 2013
Swap	Credit Suisse International	NYMEX	1,000	$	101.60	Jan 1, 2013 - Dec 31, 2013

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

We determine 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.  For further details regarding our derivative contracts please refer to Note 5—Commodity Derivative Instruments under Item 1 in this Quarterly Report.

Interest Rate Risk

At March 31, 2012, we had $650 million 8.125% Senior Notes outstanding due December 1, 2019, all of which has fixed rate interest.

In addition, as of March 31, 2012, we had $225.0 million available to us under our credit facility, none of which was drawn at year-end. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at March 31, 2012 under our credit facility of $225.0 million, a 1.0% increase in interest rates would result in additional annualized interest expense of approximately $2.3 million.

For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 4—Long-Term Debt under Item 1 in this Quarterly Report.

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 March 31, 2012. 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, as appropriate to allow timely decisions regarding required disclosure.

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

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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, 2011, as filed with the SEC on February 28, 2012.  The risk factors in our Annual Report on Form 10-K for the year ended December 31, 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.  MINE SAFETY DISCLOSURES

These disclosures are not applicable to us.

ITEM 5.  OTHER INFORMATION

None.

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ITEM 6.  EXHIBITS

Exhibit Number	Description
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.

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SIGNATURES

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

	KODIAK OIL & GAS CORP.
May 3, 2012	/s/ LYNN A. PETERSON
	Lynn A. Peterson President and Chief Executive Officer
May 3, 2012	/s/ JAMES P. HENDERSON
	James P. Henderson Chief Financial Officer (principal financial and accounting officer)

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