Kodiak Oil & Gas (KOG) 10-Q 2012 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 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

264,050,077 shares, no par value, of the Registrant’s common stock were issued and outstanding as of October 31, 2012.

KODIAK OIL & GAS CORP.

INDEX

PART 1—FINANCIAL INFORMATION		3
ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	3
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	23
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35
ITEM 4.	CONTROLS AND PROCEDURES	37
PART II—OTHER INFORMATION		37
ITEM 1.	LEGAL PROCEEDINGS	37
ITEM 1A.	RISK FACTORS	37
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	37
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	37
ITEM 4.	MINE SAFETY DISCLOSURES	37
ITEM 5.	OTHER INFORMATION	37
ITEM 6.	EXHIBITS	38
SIGNATURES		39

2

PART 1—FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

	September 30, 2012			December 31, 2011
ASSETS
Current Assets:
Cash and cash equivalents	$	1,750		$	81,604
Cash held in escrow	—			12,194
Accounts receivable
Trade	38,925			28,835
Accrued sales revenues	48,088			21,974
Commodity price risk management asset	11,650			—
Inventory, prepaid expenses and other	24,723			24,294
Total Current Assets	125,136			168,901
Oil and gas properties (full cost method), at cost:
Proved oil and gas properties	1,639,535			598,065
Unproved oil and gas properties	455,836			263,462
Wells in progress	98,898			78,505
Equipment and facilities	19,108			11,186
Less-accumulated depletion, depreciation, amortization, and accretion	(238,995		)	(135,586		)
Net oil and gas properties	1,974,382			815,632
Cash held in escrow	—			691,764
Commodity price risk management asset	5,958			—
Property and equipment, net of accumulated depreciation of $964 at September 30, 2012 and $618 at December 31, 2011	1,824			1,276
Deferred financing costs, net of accumulated amortization of $17,154 at September 30, 2012 and $15,029 at December 31, 2011	25,474			21,904
Total Assets	$	2,132,774		$	1,699,477
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	160,027		$	78,402
Accrued interest payable	21,848			5,808
Commodity price risk management liability	—			11,925
Total Current Liabilities	181,875			96,135
Noncurrent Liabilities:
Credit facilities	115,000			100,000
Senior notes, net of accumulated amortization of bond premium of $225 at September 30, 2012 and $0 at December 31, 2011	805,775			650,000
Commodity price risk management liability	3,180			10,035
Deferred tax liability, net	21,940			—
Asset retirement obligations	7,654			3,627
Total Noncurrent Liabilities	953,549			763,662
Total Liabilities	1,135,424			859,797
Stockholders’ Equity:
Common stock - no par value; unlimited authorized
Issued and outstanding: 263,936,608 shares as of September 30, 2012 and 257,987,413 shares as of December 31, 2011	1,003,448			944,070
Accumulated deficit	(6,098		)	(104,390		)
Total Stockholders’ Equity	997,350			839,680
Total Liabilities and Stockholders’ Equity	$	2,132,774		$	1,699,477

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

3

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenues:
Oil sales	$	106,798		$	28,151		$	266,002		$	62,588
Gas sales	5,342			1,377			11,842			2,387
Total revenues	112,140			29,528			277,844			64,975
Operating expenses:
Oil and gas production	22,950			6,505			57,450			13,512
Depletion, depreciation, amortization and accretion	43,720			6,801			104,204			15,054
General and administrative	9,126			4,549			25,166			13,069
Total operating expenses	75,796			17,855			186,820			41,635
Operating income	36,344			11,673			91,024			23,340
Other income (expense):
Gain (loss) on commodity price risk management activities	(31,652		)	18,806			40,580			13,968
Interest income (expense), net	(6,390		)	(263		)	(14,558		)	(598		)
Other income	1,194			629			3,186			920
Total other income (expense)	(36,848		)	19,172			29,208			14,290
Income (loss) before income taxes	(504		)	30,845			120,232			37,630
Income tax expense (benefit)	(3,980		)	—			21,940			—
Net income	$	3,476		$	30,845		$	98,292		$	37,630
Earnings per common share:
Basic	$	0.01		$	0.15		$	0.37		$	0.20
Diluted	$	0.01		$	0.15		$	0.37		$	0.20
Weighted average common shares outstanding:
Basic	263,756,896			202,721,678			263,332,764			186,891,361
Diluted	267,403,802			205,712,033			267,532,393			189,951,979

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

4

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	98,292		$	37,630
Reconciliation of net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	104,204			15,054
Amortization of deferred financing costs and debt premium	1,900			677
Unrealized gain on commodity price risk management activities, net	(36,388		)	(15,509		)
Stock-based compensation	7,855			3,514
Deferred income taxes	21,940			—
Changes in current assets and liabilities:
Accounts receivable-trade	(10,090		)	(6,721		)
Accounts receivable-accrued sales revenue	(26,114		)	(7,374		)
Prepaid expenses and other	7,860			6,669
Accounts payable and accrued liabilities	14,413			9,089
Accrued interest payable	(19,660		)	108
Cash held in escrow	3,343			—
Net cash provided by operating activities	167,555			43,137
Cash flows from investing activities:
Acquired oil and gas properties and facilities	(588,420		)	(71,506		)
Oil and gas properties	(491,319		)	(133,869		)
Sale of oil and gas properties	2,752			2,132
Equipment, facilities and other	(8,160		)	(2,817		)
Prepaid tubular goods	(29,920		)	(15,849		)
Cash held in escrow	30,000			(17,671		)
Net cash used in investing activities	(1,085,067		)	(239,580		)
Cash flows from financing activities:
Borrowings under credit facilities	200,000			89,808
Repayments under credit facilities	(185,000		)	(74,808		)
Proceeds from the issuance of senior notes	156,000			—
Proceeds from the issuance of common shares	1,870			169,557
Cash held in escrow	670,615			—
Debt and share issuance costs	(5,827		)	(10,671		)
Net cash provided by financing activities	837,658			173,886
Decrease in cash and cash equivalents	(79,854		)	(22,557		)
Cash and cash equivalents at beginning of the period	81,604			101,198
Cash and cash equivalents at end of the period	$	1,750		$	78,641
Supplemental cash flow information:
Oil & gas property accrual included in accounts payable and accrued liabilities	$	124,155		$	31,259
Oil & gas property acquired through common stock	$	49,798		$	14,425
Cash paid for interest	$	32,354		$	3,766
Cash paid for income taxes	$	—		$	—

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5

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 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.

Impairment of Oil and Gas Properties

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, impairment would be recognized.

6

Wells in Progress

Wells in progress represent the costs associated with wells that have not reached total depth or been completed as of period end. These costs are related to wells that are classified as both proved and unproved. Costs related to wells that are classified as proved are included in the depletion base.  Costs associated with wells that are classified as unproved are excluded from the depletion base.  The costs for unproved wells are then transferred to proved property when proved reserves are determined. The costs then become subject to depletion.

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.

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 adoption of this standard did not materially expand the condensed consolidated financial statement footnote disclosures.

In December 2011, the FASB issued Accounting Standards Update 2011-11 (“ASU 2011-11”), Balance Sheet: Disclosures about Offsetting Assets and Liabilities. The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. ASU 2011-11 is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. The adoption of this standard will not have an impact on the Company’s financial position or results of operations, but will require enhanced disclosures regarding derivative instruments.

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.

7

Note 3—Acquisitions

January 2012 Acquisition

On January 10, 2012, the Company acquired two separate private, unaffiliated oil and gas company’s 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 for a combination of cash and stock. The sellers received an aggregate of 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 as of the closing date on January 10, 2012. The acquisition provided strategic additions adjacent to the Company’s core project area and the acquired producing wells contributed revenue of $7.2 million and $27.5 million to Kodiak for the three and nine months ended September 30, 2012, respectively.  Total transaction costs related to the acquisition were approximately $295,000, of which $0 and $85,000 were recorded in the statement of operations within the general and administrative expenses line item for the three and nine months ended September 30, 2012, respectively. There were no transaction costs related to the acquisition recorded in the statement of operations within the general and administrative expenses line item for the three and nine months ended September 30, 2011. 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.  In July 2012, the Company completed the transaction’s 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):

Preliminary Purchase Price	January 10, 2012
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	313,053
Wells in progress	25,745
Equipment and facilities	7,025
Total fair value of oil and gas properties acquired	642,913
Working capital	(3,895		)
Asset retirement obligation	(800		)
Fair value of net assets acquired	$	638,218
Working capital acquired was estimated as follows:
Accounts receivable	$	7,200
Prepaid completion costs	465
Crude oil inventory	540
Accrued liabilities	(8,300		)
Suspense payable	(3,800		)
Total working capital	$	(3,895	)

*The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company’s closing stock price of $9.85 on the measurement date of January 10, 2012.

8

October 2011 Acquisition

On October 28, 2011, the Company acquired a private, unaffiliated oil and gas company’s 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 seller received cash consideration of approximately $248.2 million and the effective date was August 1, 2011, with purchase price adjustments calculated as of the closing date on October 28, 2011. The total purchase included approximately $239.9 million related to the acquisition of the properties and approximately $8.6 million related to the assumption of certain working capital items. The acquisition provided strategic additions adjacent to the Company’s core project area and the acquired producing wells contributed revenue of $6.7 million and $22.3 million to Kodiak for the three and nine months ended September 30, 2012, respectively. Total transaction costs related to the acquisition incurred were approximately $200,000, of which approximately $100,000 were recorded in the statement of operations within the general and administrative expenses line item for both the three and nine months ended September 30, 2011.  No transaction costs for this acquisition were recorded within the three and nine months ended September 30, 2012.

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 transaction’s post-closing settlement. The following table summarizes the purchase price and final allocation of the fair value of the assets acquired and liabilities assumed (in thousands):

Purchase Price	October 28, 2011
Consideration Given
Cash	$	248,213
Total consideration given	$	248,213
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

9

June 2011 Acquisition

On June 30, 2011, the Company acquired a private, unaffiliated oil and gas company’s 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 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 as of the closing date on June 30, 2011. The acquisition provided strategic additions to the Company’s core positions in Koala, Smokey and Grizzly Project areas and the acquired producing wells contributed revenue to Kodiak of $360,000 and $1.2 million for the three and nine months ended September 30, 2012, respectively, as compared to $825,000 for both the three and nine months ended September 30, 2011.  Total transaction costs related to the acquisition were approximately $265,000.  There were no transaction costs related to the acquisition recorded in the statement of operations, within the general and administrative expenses line item, for the three and nine months ended September 30, 2012. Transaction costs of $20,000 and $265,000 were recorded within the general and administrative expenses line item for the three and nine months ended September 30, 2011, respectively. 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 properties acquired in January 2012, October 2011 and June 2011 for the three and nine months ended September 30, 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 $650.0 million 8.125% Senior Notes were issued on January 1, 2011 and that the stand-by bridge previously arranged was not utilized. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $0 and $600,000 for the three and nine months ended September 30, 2012, respectively, as compared to $8.8 million and $19.5 million for the three and nine months ended September 30, 2011, respectively. The pro forma information includes the effects of adjustments for amortization of financing costs of $400,000 and $1.2 million for the three and nine months ended September 30, 2011, respectively.  For the three and nine months ended September 30, 2012, there was no pro forma adjustments for the amortization of deferred financing costs.  For the three and nine months ended September 30, 2012, there was a pro forma adjustment reducing interest expense of $0 and $400,000, respectively. For the three and nine months ended September 30, 2011, there was no pro forma adjustment for interest expense. The pro forma financial information includes total capitalization of interest expense of $11.2 million and $36.1 million for the three and nine months ended September 30, 2012, respectively, as compared to $14.7 million and $43.3 million for the three and nine months ended September 30, 2011, respectively.  The pro forma results do not include any cost savings or other synergies that may result from the 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 September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Operating revenues	$	112,140	$	51,545	$	279,644	$	112,238
Net income	$	3,476	$	38,628	$	99,516	$	54,278
Earnings per common share
Basic	$	0.01	$	0.18	$	0.38	$	0.28
Diluted	$	0.01	$	0.18	$	0.37	$	0.27

10

Note 4—Long-Term Debt

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

	September 30, 2012		December 31, 2011
Credit Facility due October 2016	$	115,000	$	—
Second Lien Credit Agreement due April 2017	—		100,000
8.125% Senior Notes due December 2019	800,000		650,000
Unamortized Premium on 8.125% Senior Notes	5,775		—
Total Long-Term Debt	$	920,775	$	750,000
Less: Current Portion of Long Term Debt	—		—
Total Long-Term Debt, Net of Current Portion	$	920,775	$	750,000

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 borrowing base of $375.0 million at September 30, 2012.  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.

On October 15, 2012, the Company completed its regular semi-annual redetermination of the borrowing base. Following the redetermination, the Company’s borrowing base increased from $375.0 million to $450.0 million.  The Company and its lenders also entered into an amendment to the credit facility that allows the Company to increase the borrowing base without increasing the aggregate commitment from its lenders.  The Company elected to have the lenders’ aggregate commitment remain at $375.0 million.

Interest on the credit facility 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 September 30, 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 September 30, 2012, the Company was in compliance with all financial covenants under the credit facility.

As of September 30, 2012, the Company had $115.0 million in outstanding borrowings under the credit facility and as such, the available credit under the credit facility at that date was $260.0 million. 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 several counterparties that are also lenders under the credit facility. The Company’s obligations under these hedging contracts are secured by the credit facility.

11

Second Lien Credit Agreement

On January 10, 2012, Kodiak Oil & Gas (USA) Inc. 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

In November 2011, the Company issued at par $650.0 million of 8.125% Senior Notes due December 1, 2019 (the “Senior Notes”). On May 17, 2012, the Company issued an additional $150.0 million aggregate principal amount of our existing 8.125% Senior Notes at a price of 104.0% of par, resulting in net proceeds of $151.8 million, after deducting discounts and fees. The net proceeds from the May 2012 offering were used to repay all outstanding borrowings on the credit facility at that time and to fund the Company’s ongoing capital expenditure program and general corporate purposes. The interest on the Senior Notes is payable on June and December 1 of each year, beginning June 1, 2012. 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 September 30, 2012, 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 September 30, 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 registration rights agreements that provide 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 agreements, 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 agreements. If the Company fails to comply with certain obligations under the agreements, it will be required to pay liquidated damages by way of additional interest on the Senior Notes. On July 20, 2012, the Company filed a registration statement on Form S-4 (No. 333-182783, amended on October 9, 2012 and declared effective by the SEC on October 11, 2012) with the SEC in accordance with such registration rights agreements.  On October 12, 2012, the Company commenced such registered exchange offer.  The exchange offer will expire on November 9, 2012, unless otherwise extended.

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Deferred Financing Costs

As of September 30, 2012, the Company had deferred financing costs of $25.5 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.  The Company recorded amortization expense for the three and nine months ended September 30, 2012 of $794,000 and $2.1 million, respectively, as compared to $289,000 and $677,000 for the three and nine months ended September 30, 2011, respectively.

Interest Incurred On Long-Term Debt

Total interest expense incurred during the three and nine months ended September 30, 2012 was approximately $17.0 million and $45.4 million, respectively, as compared to $1.5 million and $3.8 million for the three and nine months ended September 30, 2011, respectively.  The Company capitalized interest costs of $11.2 million and $35.7 million for the three and nine months ended September 30, 2012, respectively, as compared to $1.5 million and $3.8 million for the three and nine months ended September 30, 2011, respectively.  Additionally, interest expense was reduced for the amortization of the bond premium in the amounts of $151,000 and $224,000 for the three and nine months ended September 30, 2012.

Note 5— 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.  Through March 31, 2012, the Company had a full valuation allowance against both its U.S. and Canadian net deferred tax assets; since it could not conclude that it was more likely than not that the net deferred tax assets would have been fully realized. This conclusion was based on the fact that the Company had not generated cumulative taxable income through March 31, 2012 and had incurred a cumulative book loss over the previous three fiscal years.  However, during the second quarter of 2012, the Company concluded that it is more likely than not that it would be able to realize the benefits of its U.S. deferred tax assets, and that it was appropriate to release the U.S. valuation allowance against its U.S. deferred tax assets.  This decision was based on the fact that for the three-year period ended June 30, 2012, the Company had reported positive cumulative net income.

The Company continues to provide a full valuation allowance on the Canadian net deferred tax assets as ultimate realization of these 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.  As the Company does not have revenue generating assets in Canada, the Company does not expect to utilize the Canadian net deferred tax assets.  The Company will continue to evaluate whether a valuation allowance on a separate country basis is needed in future reporting periods.

The Company recognized an income tax benefit of $4.0 million for the three months ended September 30, 2012 and recognized income tax expense of $21.9 million for the nine months ended September 30, 2012. For the three and nine months ended September 30, 2011 no income tax expense or benefit was recognized.  The income tax benefit recorded for the three months ended September 30, 2012 varies from the statutory income tax rate due to the change in the estimated annual effective tax rate from the second quarter to the third quarter of 2012.

The effective tax rate for the nine months ended September 30, 2012, was 18.26%, which differs from the statutory federal income tax rate as shown in the below table.  Our actual effective tax rate for 2012 could vary significantly from this rate based on our actual results.

	For the Nine Months Ended September 30, 2012
Federal	35.00	%
State	2.14	%
Other	1.04	%
Change in Valuation Allowance (U.S.)	-20.22	%
Change in Valuation Allowance (Canada)	0.30	%
Net	18.26	%

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The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2012, the Company had no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in Canada and U.S. federal jurisdiction and various states. There are currently no Canadian or U.S. federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service, state or local tax authorities for tax years ended on or before December 31, 2008 or Canadian tax examinations by the Canadian Revenue Agency for tax years ended on or before December 31, 2001. 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.

Note 6— 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 four 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 statements of operations. 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 September 30, 2012 are summarized below:

Contract Type	Counterparty	Basis(1)	Quantity (Bbl/d)	Strike Price ($/Bbl)	Term
Collar	Wells Fargo Bank, N.A.	NYMEX	400	$70.00 - $95.56	Oct 1, 2012—Dec 31, 2012
Collar	Wells Fargo Bank, N.A.	NYMEX	230	$85.00 - $117.73	Oct 1, 2012—Dec 31, 2012
Collar	Shell Trading (U.S.)	NYMEX	500	$85.00 - $117.00	Oct 1, 2012—Dec 31, 2013
Collar	Wells Fargo Bank, N.A.	NYMEX	300 - 425	$85.00 - $102.75	Jan 1, 2013—Dec 31, 2015
Contract Type	Counterparty	Basis(1)	Quantity (Bbl/d)	Swap Price ($/Bbl)	Term
Swap	Wells Fargo Bank, N.A.	NYMEX	100	$84.00	Oct 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	136	$88.30	Oct 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	24	$90.28	Oct 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$85.00	Oct 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$85.07	Oct 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$102.05	Oct 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$102.88	Oct 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$107.20	Oct 1, 2012—Dec 31, 2012
Swap	Wells Fargo Bank, N.A.	NYMEX	250	$100.20	Oct 1, 2012—Dec 31, 2012
Swap	Shell Trading (U.S.)	NYMEX	250	$85.01	Oct 1, 2012—Dec 31, 2012
Swap	Shell Trading (U.S.)	NYMEX	2,000	$96.88	Oct 1, 2012—Dec 31, 2012
Swap	Shell Trading (U.S.)	NYMEX	500	$102.85	Oct 1, 2012—Dec 31, 2012
Swap	Shell Trading (U.S.)	NYMEX	500	$99.27	Oct 1, 2012—Dec 31, 2012
Swap	Credit Suisse International	NYMEX	500	$106.85	Oct 1, 2012—Dec 31, 2012
Swap	Credit Suisse International	NYMEX	500	$107.25	Oct 1, 2012—Dec 31, 2012
Swap	Credit Suisse International	NYMEX	1,000	$102.83	Oct 1, 2012—Dec 31, 2012
Swap	Credit Suisse International	NYMEX	250	$100.35	Oct 1, 2012—Dec 31, 2012
2012 Total/Average			10,010	$98.38
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	Wells Fargo Bank, N.A.	NYMEX	1,000	$101.55	Jan 1, 2013—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	1,000	$95.95	Jan 1, 2013—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$92.30	Jan 1, 2013—Dec 31, 2013
Swap	Wells Fargo Bank, N.A.	NYMEX	500	$97.70	Jan 1, 2013—Dec 31, 2013
Swap	Shell Trading (U.S.)	NYMEX	250	$85.01	Jan 1, 2013—Dec 31, 2013
Swap	Shell Trading (U.S.)	NYMEX	500	$101.32	Jan 1, 2013—Dec 31, 2013
Swap	Shell Trading (U.S.)	NYMEX	500	$95.98	Jan 1, 2013—Dec 31, 2013
Swap	Shell Trading (U.S.)	NYMEX	500	$92.51	Jan 1, 2013—Dec 31, 2013
Swap	Credit Suisse International	NYMEX	1,000	$101.60	Jan 1, 2013—Dec 31, 2013
Swap	Credit Suisse International	NYMEX	1,000	$95.98	Jan 1, 2013—Dec 31, 2013
Swap	KeyBank	NYMEX	1,000	$92.40	Jan 1, 2013—Dec 31, 2013
Swap	KeyBank	NYMEX	500	$97.70	Jan 1, 2013—Dec 31, 2013
2013 Total/Average			11,105	$95.84
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	317	$88.30	Jan 1, 2015—Sept 30, 2015
Swap	Wells Fargo Bank, N.A.	NYMEX	59	$84.00	Jan 1, 2015—Oct 31, 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

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

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

Underlying Commodity	Location on Balance Sheet	As of September 30, 2012		As of December 31, 2011
Crude oil derivative contract	Current assets	$	11,650	$	—
Crude oil derivative contract	Noncurrent assets	$	5,958	$	—
Crude oil derivative contract	Current liabilities	$	—	$	11,925
Crude oil derivative contract	Noncurrent liabilities	$	3,180	$	10,035

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012		2011
Unrealized gain (loss) on oil contracts	$	(36,696	)	$	19,012		$	36,388	$	15,509
Realized gain (loss) on oil contracts	5,044			(206		)	4,192		(1,541		)
Gain (loss) on commodity price risk management activities	$	(31,652	)	$	18,806		$	40,580	$	13,968

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 statements of operations.

Note 7—Asset Retirement Obligations

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

	For the Nine Months Ended September 30, 2012			For the Year Ended December 31, 2011
	(in thousands)
Balance beginning of period	$	3,627		$	1,968
Liabilities incurred or acquired	3,310			1,655
Liabilities settled	(58		)	(610		)
Revisions in estimated cash flows	405			418
Accretion expense	370			196
Balance end of period	$	7,654		$	3,627

Note 8—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:

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·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 7—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 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 September 30, 2012 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at September 30, 2012 Using
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity price risk management asset	$	—	$	17,608	$	—	$	17,608
Financial Liabilities:
Commodity price risk management liability	$	—	$	3,180	$	—	$	3,180

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 September 30, 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, accounts receivable and 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.

	As of September 30, 2012				As of December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Credit Facility	$	115,000	$	115,000	$	—	$	—
Second Lien Credit Agreement	$	—	$	—	$	100,000	$	103,000
8.125% Senior Notes	$	805,775	$	852,000	$	650,000	$	656,500

Note 9—Share-Based Payments

The Company has granted options to directors, officers, and employees of the Company under the 2007 Stock Incentive Plan, amended on June 3, 2010 and further amended on June 15, 2011 (the ��Plan”). 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, 2012, the maximum number of shares issuable under the Plan, including those previously issued thereunder, was approximately 36.1 million shares.

Stock Options

Total compensation expense related to the stock options of $1.7 million and $4.7 million was recognized during the three and nine months ended September 30, 2012, respectively, as compared to $734,000 and $2.7 million for the three and nine months ended September 30, 2011, respectively. As of September 30, 2012, there was $8.2 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted-average period of 1.9 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 periods presented:

	For the Nine Months Ended September 30, 2012		For the Year Ended December 31, 2011
Risk free rates	0.78 - 1.48%		1.06 - 2.57%
Dividend yield	0%		0%
Expected volatility	86.69 - 90.25%		90.43 - 94.97%
Weighted average expected stock option life	5.84 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	$	6.59	$	5.10
Total options granted	1,065,500		1,712,500
Total weighted average fair value of options granted	$	7,021,645	$	8,733,750

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A summary of the stock options outstanding as of January 1, 2012 and September 30, 2012 is as follows:

			Weighted
			Average
	Number of		Exercise
	Options		Price
Balance outstanding at January 1, 2012	6,591,158		$	3.77
Granted	1,065,500		9.08
Canceled	(329,035	)	6.25
Exercised	(863,583	)	2.17
Balance outstanding at September 30, 2012	6,464,040		$	4.74
Options exercisable at September 30, 2012	3,877,540		$	3.16

At September 30, 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	241,000	6.2	$	0.36	241,000	6.2	$	0.36
$1.01-$2.00	670,917	1.6	$	1.18	670,917	1.6	$	1.18
$2.01-$3.00	869,870	6.9	$	2.36	591,870	6.7	$	2.34
$3.01-$4.00	1,793,253	3.9	$	3.47	1,716,253	3.7	$	3.46
$4.01-$5.00	155,000	8.5	$	4.47	35,000	8.3	$	4.46
$5.01-$6.00	242,500	8.7	$	5.57	73,500	8.7	$	5.58
$6.01-$7.00	1,093,000	7.4	$	6.41	533,000	6.2	$	6.34
$7.01-$8.00	310,000	9.4	$	7.48	16,000	8.4	$	7.20
$8.01-$9.00	501,000	9.4	$	8.74	—	—	$	—
$9.01-$10.53	587,500	9.3	$	9.76	—	—	$	—
	6,464,040	6.2	$	4.74	3,877,540	4.5	$	3.16

The aggregate intrinsic value of both outstanding and vested options as of September 30, 2012 was $30.1 million based on the Company’s September 28, 2012 closing common stock price of $9.36 per share. The total grant date fair value of the shares vested during the first nine months of 2012 was $2.7 million.

Restricted Stock Units and Restricted Stock

Total compensation expense related to restricted stock units (“RSUs”) and restricted stock of $1.1 million and $3.2 million was recognized during the three and nine months ended September 30, 2012, respectively, as compared to $294,000 and $826,000 for the three and nine months ended September 30, 2011, respectively. As of September 30, 2012, there was $4.5 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 2.0 years.

In the fourth quarter 2011, the Company awarded 775,611 performance based RSUs to officers pursuant to the 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 RSUs granted is based on the stock price on the grant date and the Company assumed no annual forfeiture rate.

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During 2012, the Company awarded 30,000 shares of restricted stock to its Board of Directors pursuant to the 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 nine months 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 September 30, 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 first nine months of 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 and RSUs at January 1, 2012	1,008,111		$	8.48
Granted	30,000		9.87
Forfeited	—		—
Vested	(22,500	)	7.39
Non-vested restricted stock and RSUs at September 30, 2012	1,015,611		$	8.55

Note 10—Earnings Per Share

Basic net income or loss per share is computed by dividing net income or 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 9—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 per share for the three and nine months ended September 30, 2012 and 2011 (in thousands, except per share data):

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
Basic net income	$	3,476		$	30,845		$	98,292		$	37,630
Income allocable to participating securities	(1		)	(3		)	(11		)	(5		)
Diluted net income	$	3,475		$	30,842		$	98,281		$	37,625
Basic weighted average common shares outstanding	263,756,896			202,721,678			263,332,764			186,891,361
Effect of dilutive securities
Options to purchase common shares	5,816,540			4,866,658			5,876,540			5,051,658
Assumed treasury shares purchased	(2,612,388		)	(2,156,303		)	(2,031,462		)	(2,271,040		)
Unvested restricted stock units	442,754			280,000			354,551			280,000
Diluted weighted average common shares outstanding	267,403,802			205,712,033			267,532,393			189,951,979
Basic net income per share	$	0.01		$	0.15		$	0.37		$	0.20
Diluted net income per share	$	0.01		$	0.15		$	0.37		$	0.20

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

	For the Three Months Ended September 30,		For the Nine Months Ended September 30,
	2012	2011	2012	2011
Anti-dilutive shares	647,500	1,334,500	587,500	1,149,500

Note 11—Commitments and Contingencies

Lease Obligations

The Company leases office space in Denver, Colorado and Dickinson and Williston, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on April 30, 2016. The Dickinson and Williston, North Dakota leases expire on December 31, 2013 and May 31, 2013, respectively. Total rental commitments under non-cancelable leases for office space were $3.3 million at September 30, 2012.  The future minimum lease payments under these non-cancelable leases are as follows: $190,000 in 2012, $820,000 in 2013, $770,000 in 2014, $810,000 in 2015, and $700,000 in 2016.

Drilling Rigs

As of September 30, 2012, the Company was subject to commitments on seven drilling rig contracts.  In the event of early termination under these contracts, the Company would be obligated to pay an aggregate amount of approximately $40.7 million as of September 30, 2012 as required under the varying terms of such contracts.

Pressure Pumping Services

As of September 30, 2012, the Company was subject to a commitment with a pressure-pumping service company providing 24-hour per day crew availability.  In the event of early contract termination, the Company would be obligated to pay approximately $30.0 million as of September 30, 2012.

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Guarantees of the Senior Notes

In November 2011 and May 2012, the Company issued Senior Notes due in 2019 in the amounts of $650.0 million and $156.0 million (including a $6.0 million premium on the issuance), respectively, which notes 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. Such guarantee is full and unconditional, and the parent company has no other subsidiaries. In addition, there are no restrictions under the Senior Notes or the associated guarantees 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, changes 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 production or oil prices, and the impact of general economic conditions on the demand for oil and natural gas;

·geographical concentration of our operations;

·constraints imposed on our business and operations by our long term debt (credit agreement and Senior Notes) and our ability to generate sufficient cash flows to repay our debt obligations;

·availability of borrowings under our credit agreement;

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

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

·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;

·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;

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·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;

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

·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 and the volatility of the market for our shares.

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 associated natural gas in the Rocky Mountain region of the United States. We have developed an asset base of proved reserves, as well as a portfolio of development and exploratory opportunities on high-potential oil resource plays.  Our reserves and operations are concentrated in the Williston Basin of North Dakota.  As of September 30, 2012, we owned an interest in approximately 232,000 gross (153,000 net) acres in the Williston Basin where our primary target is the middle Bakken and Three Forks formations.  As of September 30, 2012, we have an interest in 228 gross (95.0 net) producing wells in the Williston Basin.

Recent Developments

Operational Update

As of the date of this filing, we are operating eight drilling rigs on our acreage.  We are releasing one drilling rig in early November and we anticipate operating seven drilling rigs into 2013. Drilling operations continue to benefit from improved efficiencies resulting in decreased spud-to-rig-release drilling times.  Drilling costs continue to decline as a result of these efficiencies, as well as from cost reductions across the full spectrum of oil field goods and services.  With improved drilling efficiencies, it is now possible to drill more wells with fewer rigs.

We are currently operating with two full-time, 24-hour-per-day completion crews which are expected to remain active through year-end 2012.  Most of the wells remaining to be completed during the fourth quarter 2012 have already been drilled and surface facilities and pipelines are being installed ahead of completion efforts.

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During the fourth quarter of 2012, we expect to complete 26 gross (23 net) operated wells. We also continue to participate as non-operator in the drilling and completion of wells within the area of mutual interest (“AMI”) area in Dunn County, North Dakota where two rigs are currently drilling, as well as other non-operated wells outside of the AMI.  The following table summarizes the wells spud and completed during the three and nine months ended September 30, 2012:

	Spud		Completed
	Gross	Net	Gross	Net
For the Three Months Ended September 30, 2012
Operated wells	21	18.2	15	10.8
Non-operated wells	21	4.5	10	1.4
	42	22.7	25	12.2

	Spud		Completed
	Gross	Net	Gross	Net
For the Nine Months Ended September 30, 2012
Operated wells	49	41.1	41	31.5
Non-operated wells	51	10.1	43	7.8
	100	51.2	84	39.3

Oil, gas and water infrastructure continues to improve throughout the Williston Basin.  The majority of our wells in Dunn County are connected to pipeline infrastructure to transport oil, gas and water.  However, the ability to sell and process gas from these wells continues to be constrained due to gathering system pressure restrictions.  Some of these restrictions are being eliminated as additional capacity has been brought on-line and the addition of natural gas compression.  In McKenzie County, the majority of our wells have been connected to gas pipelines and, in most cases, oil pipelines. Currently most of our wells in Williams County have been connected to gas pipelines and oil pipelines should be constructed during the first half of 2013.  Throughout the Basin sales of natural gas continues to be dependent on processing plant capacity and the timing of connecting gas pipelines to newly completed wells.

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

Kodiak Oil & Gas Corp.

Q3 2012 Bakken and Three Forks Completion Activities

				Production Volumes (BOE/d)
Well Name	WI / NRI (%)	Formation	Length of Lateral	IP 24 Hour Test	30 Day Average	60 Day Average
Dunn County, ND
Skunk Creek 2-24-25-16H (1)	97 / 80	Bakken	9,570’	2,094	925	—
Skunk Creek 2-8-17-15H (1)	44 / 38	Bakken	9,250’	1,814	833	—
Two Shields Butte 5-7-8-1H	50 / 41	Bakken	9,678’	2,775	—	—
Two Shields Butte 5-7-8-1H3	43 / 35	Three Forks	9,564’	3,008	—	—
Williams and McKenzie Counties, ND
P Vance 154-97-2-17-20-15H	82 / 68	Bakken	9,490’	3,244	1,250	928
P Vance 154-97-2-17-5-5H	61 / 51	Bakken	8,732’	2,742	1,084	860
Holland 9-19H	60 / 48	Three Forks	7,527’	225	181	204
P Alexander 155-99-16-11-2-1H	73 / 58	Bakken	9,213’	2,977	963	760
P Alexander 155-99-16-11-2-1H3	73 / 58	Three Forks	9,449’	2,700	967	757
P Alice 154-99-4-3-27-4H	57 / 46	Bakken	10,105’	3,213	1,288	985
P Alice 154-99-4-3-27-4H3	57 / 46	Three Forks	9,678’	2,895	1,110	—
Koala 14-32-29-3H	98 / 79	Bakken	9,536’	3,035	1,680	—
Koala 14-32-29-4H3	98 / 79	Three Forks	9,709’	3,124	1,330	—
Koala 14-32-29-2H3	98 / 79	Three Forks	9,588’	2,528	1,238	—
P Jorgenson 154-98-5-14-23-16H	92 / 75	Bakken	7,349’	3,666	1,403	—
Non-Operated: Dunn County, ND
FBIR Hunts Along 31X-2	38 / 31	Bakken		Well on confidential status

(1) Indicates remediated well with successful liner patch

Regulatory Matters

On April 17, 2012, the Environmental Protection Agency 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 and National Emission Standards for Hazardous Air Pollutants programs. The Environmental Protection Agency rules include standards under the New Source Performance 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”. The finalized rules also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. At this time, we believe we are in compliance with these regulations and do not expect them to have a material impact on our operations.

On August 15, 2012, the EPA issued the final rule “Federal Implementation Plan for Oil and Natural Gas Production Facilities, Fort Berthold Indian Reservation, North Dakota,” which regulates oil and natural gas operations on the Fort Berthold Indian Reservation in North Dakota.  The new rule requires oil and gas owners and operators to reduce emissions of volatile organic compounds from oil and natural gas well completions. recompletions, and production and storage operations.

On May 11, 2012, the Bureau of Land Management published proposed rules to regulate hydraulic fracturing on federal public lands and Indian lands. The proposed rules would address well stimulation operations, including requiring agency approval for certain activities, and would require the disclosure of well stimulation fluids, as well as address issues relating to flowback water. If adopted, these rules may require changes to our operations, lead to operational delays and/or increased operating costs, and result in greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. The rules are expected to be finalized by the end of 2012. We are currently evaluating the effect these proposed rules would have on our business and financial condition.

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Capital Resources and Liquidity

2012 Capital Expenditures Budget

Our 2012 capital expenditures (“CAPEX”) budget is subject to various factors, including market conditions, oil field services and equipment availability, commodity prices and drilling results.  Commensurate with the increased well activity and costs described below, our Board of Directors has approved a revised 2012 CAPEX budget of $750 million. The following table summarizes our actual CAPEX for the nine months ended September 30, 2012, compared to our original and revised 2012 budgets:

					Nine Months Ended
	2012 Budget				September 30, 2012
	Original		Revised		Actual
	(in millions)
Operated drilling and completion costs	$	520.0	$	606.0	$	445.8
Non-operated drilling and completion costs	45.0		120.0		107.5
Salt water disposal wells and facilities	10.0		12.0		11.2
Leasehold acquisitions	10.0		12.0		11.4
	$	585.0	$	750.0	$	575.9

During the nine months ended September 30, 2012, we incurred CAPEX of $575.9 million related to drilling and completion operations, related infrastructure and leasehold acquisitions (exclusive of our January 2012 acquisition and capitalized interest of $35.7 million). This total includes approximately $27.0 million associated with wells awaiting remediation and a $20.4 million increase in expenditures related to wells in progress as of September 30, 2012 over the December 31, 2011 balance, reflecting our escalated operating activity. At any given time we expect to have an inventory of wells in progress of approximately 2.5 times our rig count.  We have been operating 8 rigs in 2012 compared to five rigs in 2011 and therefore we have seen the corresponding increase in wells in progress.

Exploration activity in the Williston Basin continued at a high level in 2012 and we experienced average well costs of approximately $12.5 million per well, including surface facilities and pipeline connections.  As we have moved into the fourth quarter of 2012, we have seen these costs decrease to approximately $11 million per well as drilling days have been reduced significantly and overall service costs have dropped.  Further, we recently renegotiated agreements with certain suppliers which we believe will reduce our overall well costs below $10 million per well as we go into 2013.

We project CAPEX of approximately $175 million during the fourth quarter of 2012 which would bring our full year CAPEX to $750 million. The CAPEX increase is primarily attributed to an increase in the total number of wells expected to be drilled and completed in 2012.  A large part of the increased well count is directed to our non-operated properties where we have experienced a much larger number of wells drilled this year than we anticipated.  We originally budgeted $45 million for these non-operated interests, but have invested over $100 million through September 30, 2012, and anticipate an additional $40 million in non-operated capital investment by year end.  These non-operated interests are adjacent to our core acreage blocks, and we believe it is important to elect to participate in the drilling of the wells in order to retain our economic interests in the lands and develop our Williston Basin asset base. Overall, we expect to end the year with approximately 66 net wells completed, compared to our original estimated well count of 51 net wells.

Working Capital

We expect to maintain low cash and cash equivalent balances going forward, as we typically use available funds to reduce any 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) is not considered working capital, we may have low or negative working capital at any given time.  Our working capital was a deficit of $56.7 million at September 30, 2012, as compared to a positive $20.1 million at June 30, 2012, a deficit of $56.9 million at March 31, 2012, and a positive $72.8 million at December 31, 2011.

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 the remainder of our 2012 capital program and meeting our debt service requirements primarily through operating cash flows and credit expected to be available through our borrowing base facility.  The following is a discussion of each of these expected sources of cash:

Cash flow from operations.  We expect our cash flow from operations to continue to increase commensurate with our anticipated increase in sales volumes.  We have been able to increase our volumes on a quarter over quarter basis for the past two years. This increase is directly related to our successful operations as we have developed our properties.  If we are able to continue to drill and complete our wells as anticipated and they produce at rates similar to those generated by our existing wells, subject to the changes in the market price of crude oil, we would expect our production rates and operating cash flows to continue to increase as we continue to develop our properties.

We have several multiple-well pads where drilling operations have been finished and completion operations are currently ongoing or will commence by year end.  We have 26 net wells (operated and non-operated) scheduled for completion in the fourth quarter of 2012, which should result in a significant increase in production.  However, as the wells are being completed near year end, the resulting anticipated production will have minimal impact on fourth quarter 2012 production but will be more fully realized in early 2013.

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Credit Facility. In October 2012, we completed our regular semi-annual redetermination of the borrowing base. Following the redetermination, our borrowing base increased from $375.0 million to $450.0 million.  We also entered into an amendment with our lenders that allows us to increase the borrowing base without increasing the aggregate commitment.  We elected to have the lenders’ aggregate commitment remain at $375.0 million. The ability to maintain and increase 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 our credit facility please refer to Note 4—Long-Term Debt under Item 1 in this Quarterly Report.

We expect that our cash flows from operations, cash on hand and the availability under our revolving credit facility will be sufficient to meet our remaining 2012 capital expenditures budget, our obligations under our Senior Notes and other contractual commitments (please refer to Note 11—Commitments and Contingencies under Item 1 in this Quarterly Report). If our existing and potential sources of liquidity are not 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 a change in commodity price or oil field service environment.  In the event we had to reduce the level of activity, we may incur termination fees depending on the timing and contractual requirements of our drilling rig and completions services contracts.  However, the majority of our acreage is currently producing and the remaining acreage could be held by production within the primary term of the lease, even with a reduced number of drilling rigs.

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, would be described in detail in a prospectus supplement at the time of any such offering.

Cash Flow Analysis

The following is a summary of our change in cash and cash equivalents for the nine month periods as of September 30, 2012 and September 30, 2011 (in thousands):

	For the Nine Months Ended September 30,						Period to period
	2012			2011			change
Net cash provided by operating activities	$	167,555		$	43,137		$	124,418
Net cash used in investing activities	(1,085,067		)	(239,580		)	(845,487		)
Net cash provided by financing activities	837,658			173,886			663,772
Decrease in cash and cash equivalents	$	(79,854	)	$	(22,557	)	$	(57,297	)

Net cash provided by operating activities.  The key components of our net cash provided by operating activities are our sales volumes (in particular, our crude oil sales volumes) and commodity prices (in particular, crude oil prices).  For the first nine months of 2012 as compared to the same period in 2011, our net cash provided by operating activities increased by $124.4 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.  However, the increase in our net cash provided by operations was negatively impacted by the decrease in crude oil prices for the first nine months of 2012 as compared to the same period in 2011.  The impact of the decrease in crude oil prices was partially mitigated through the use of derivative instruments as discussed previously.  Refer to the Operating Results section below for further analysis on the changes in the net cash provided by operating activities.

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 nine months of 2012 as compared to the same period in 2011, our net cash used in investing activities increased by $845.5 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 nine months of 2012 as compared to the same period in 2011.

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Net cash provided by financing activities.  For the first nine months of 2012 as compared to the same period in 2011, our net cash provided by financing activities increased by $663.8 million.  This was a result of our receipt from escrow of $670.6 million, from our November 2011 Senior Notes offering ($588.4 million of which was used to fund our January 2012 acquisition and $100.0 million of which was used to repay our second lien credit agreement) and the receipt of $151.8 million in net proceeds from our May 2012 Senior Notes offering.

Our Properties

Williston Basin (153,000 net acres)

Our Williston Basin acreage is located primarily in Dunn, McKenzie and Williams counties, of North Dakota. The primary geologic target is the Bakken pool which consists of two producing intervals.  One of the targets is the dolomitic, interval located between the upper and lower Bakken shales, at an approximate vertical depth of 10,300-11,500 feet, and the second is the Three Forks, consisting of interbedded fine grain siltstones and carbonate cement, immediately below the lower Bakken shale.

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 thousand barrels of oil equivalent (“MBOE”).

Our Leasehold

As of September 30, 2012, we had several hundred lease agreements representing approximately 261,000 gross and 163,000 net acres primarily in the Williston and Green River Basins. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

	Undeveloped Acreage(1)		Developed Acreage(2)		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Green River Basin
Wyoming	13,783	3,772	8,593	1,795	22,376	5,567
Colorado	4,805	3,040	1,894	1,280	6,699	4,320
Williston Basin
Montana	—	—	3,359	2,051	3,359	2,051
North Dakota	110,049	73,088	118,735	77,578	228,784	150,666
Acreage Totals	128,637	79,900	132,581	82,704	261,218	162,604

(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) 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 (ii) the existing lease is renewed; or (iii) it is contained within a federal unit. Based on our current drilling plans we do not expect to lose any material acreage through expiration. 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	10,383	6,535
December 31, 2013	26,215	17,716
December 31, 2014	36,744	21,703
December 31, 2015	15,291	7,437
Total	88,633	53,391

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 September 30,			For the Nine Months Ended September 30,
	2012	2011		2012	2011
Sales Volume (Bakken):
Oil (MBbls)	1,283.0	333.8		3,196.6	699.5
Gas (MMcf)	1,010.8	139.7		2,167.4	242.2
Sales Volume (Other):
Oil (MBbls)	4.4	7.4		13.2	22.9
Gas (MMcf)	17.0	-4.7	(2)	33.7	42.1
Sales Volume (Total):
Oil (MBbls)	1,287.4	341.2		3,209.8	722.4
Gas (MMcf)	1,027.8	135.0		2,201.1	284.3
Sales volumes (MBOE)	1,458.7	363.7		3,576.6	769.7
Natural Gas flared (MMcf) (1):	881.9	241.5		2,206.8	473.5
Total production volume (Total):
Oil (MBbls)	1,263.2	352.1		3,199.2	731.7
Gas (MMcf)	1,909.7	376.5		4,407.9	757.8
Production volumes (MBOE)	1,581.5	414.9		3,933.9	858.0

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

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

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Sales prices received, and production costs per sold BOE for the three and nine months ended September 30, 2012 and 2011 are summarized in the following table:

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2012		2011			2012		2011
Sales Price:
Oil ($/Bbls)	$	82.96	$	82.51		$	82.87	$	86.65
Gas ($/Mcf) (1)	$	5.20	$	10.20		$	5.38	$	8.39
Commodity Price Risk Management Activities ($/Sales BOE):
Realized gain (loss)	$	3.46	$	(0.56	)	$	1.17	$	(2.00	)
Production costs ($/Sales BOE):
Lease operating expenses	$	5.77	$	8.14		$	6.06	$	7.46
Production and property taxes	$	8.19	$	8.83		$	8.24	$	9.34
Gathering, transportation, marketing	$	1.77	$	0.91		$	1.77	$	0.75
DDA	$	29.97	$	18.70		$	29.13	$	19.56
G&A	$	6.26	$	12.51		$	7.04	$	16.98
Stock-based compensation	$	1.90	$	2.83		$	2.20	$	4.56

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

Three months ended September 30, 2012 Compared to Three months ended September 30, 2011

Oil sales revenues.  Oil sales revenues increased by $78.6 million to $106.8 million for the three months ended September 30, 2012, as compared to oil sales of $28.2 million for the same period in 2011. Our oil sales volume increased 277% to 1,287.4 thousand barrels (MBbls) in the third quarter of 2012 as compared to 341.2 MBbls for the same period of 2011. The average price we realized on the sale of our oil was $82.96 per barrel in the third quarter of 2012 compared to $82.51 per barrel for the same period in 2011. The volume increase is due to the development of our Bakken properties as well as the October 2011 and January 2012 property acquisitions.  Of the 946.2 MBbls increase in sales volume, 166.8 MBbls is related to producing wells acquired in these acquisitions and 779.4 MBbls is attributed to our ongoing development of our legacy properties and undeveloped acreage.  Overall, 99.8% of the increase in oil sales revenue was attributed to increased volumes and 0.2% was attributed to the increase in crude oil prices received.

Natural gas sales revenues.  Natural gas sales revenues increased by $3.9 million to $5.3 million for the three months ended September 30, 2012, as compared to natural gas sales revenues of $1.4 million for the same period in 2011. Natural gas sales volumes increased 661% to 1,027.8 million cubic feet (MMcf) in the third quarter of 2012 compared 135.0 MMcf for the same period in 2011. The average price we realized on the sale of our natural gas was $5.20 per Mcf in the third quarter of 2012 as compared to $10.20 per Mcf for the same period in 2011.  Overall, 117.0% of the increase in natural gas sales revenue was attributed to increased volumes and negative 17.0% was attributed to the decrease in natural gas prices received. The volume increase is due to the development of our Bakken properties as well as the October 2011 and January 2012 property acquisitions.  Of the 892.8 MMcf increase in sales volume, 128.6 MMcf is related to producing wells acquired in these acquisitions and 764.2 MMcf is attributed to our ongoing development of our legacy properties and acquired undeveloped acreage.  Although gas from certain 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.  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 production expense increased by $16.5 million to $23.0 million for the three months ended September 30, 2012 as compared to $6.5 million for the same period in 2011. The increase is due to an $8.7 million increase in production taxes, a $5.5 million increase in lease operating expenses (“LOE”) and a $2.3 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 in which we participate in. On a per unit basis, LOE decreased from $8.14 per barrel sold in the third quarter of 2011 to $5.77 for the same period 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.  Availability of both trucking and third party disposal facilities has improved, which has decreased our LOE on a per unit basis.

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To further reduce water disposal costs, in 2012, we have drilled water disposal wells on several of our producing areas and are constructing water gathering systems where appropriate. As we connect existing and future wells to these water gathering systems, we expect our LOE to continue to decrease on a per unit basis.

Depletion, depreciation, amortization and abandonment liability accretion (“DD&A”) expense.  Our depletion, depreciation, amortization and abandonment liability accretion expense increased by $36.9 million to $43.7 million for the three months ended September 30, 2012, from $6.8 million for the same period in 2011. This increase is due to increased volumes sold in the third quarter of 2012 as sales volumes increased by approximately 1,095.0 MBOE over the same period in 2011. On a per unit basis, DD&A increased from $18.70 per barrel sold in the third quarter of 2011 to $29.97 per barrel sold in the third quarter of 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 $4.6 million to $9.1 million for the three months ended September 30, 2012, from $4.5 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 104 at September 30, 2012, from 60 at September 30, 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, as amended. For the three months ended September 30, 2012, this expense was $2.8 million as compared to $1.0 million for the same period in 2011.

Operating income.  Our operating income was approximately $36.3 million for the quarter ended September 30, 2012, as compared to approximately $11.7 million for the quarter ended September 30, 2011. This increase in operating income is attributed to our acquisitions in October 2011 and January 2012 and our on-going successful completions of wells in our Bakken play.

Gain (loss) on commodity price risk management activities.  Primarily due to the increase in NYMEX crude oil prices at September 30, 2012 as compared to June 30, 2012, we incurred a total loss on our price risk management activities of $31.7 million for the three months ended September 30, 2012 compared to a gain of $18.8 million for the same period in 2011. This loss for the three months ended September 30, 2012 is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. The loss in the third quarter of 2012 was comprised of approximately $5.0 million of realized gains for transactions that were settled during the third quarter of 2012 and $36.7 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 September 30, 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 September 30, 2012, we recognized interest expense of approximately $6.4 million, as compared to $289,000 for the same period in 2011. Included in interest expense was $794,000 and $289,000 in amortization of deferred financing costs for the three months ended September 30, 2012 and 2011, respectively.  Additionally, we capitalized interest costs of $11.2 million and $1.5 million for the three months ended September 30, 2012 and 2011, respectively.

Income tax expense (benefit).  As discussed in Note 5—Income Taxes under Item 1 in this Quarterly Report, through March 31, 2012, we had a full valuation allowance against our U.S. and Canada net deferred tax assets.  During the second quarter of 2012, we concluded that it was appropriate to reverse the U.S. valuation allowance, but retained a full valuation allowance on our Canadian net deferred tax assets.  As a result we recognized a net deferred tax liability of $25.9 million as of June 30, 2012.  For the three months ended September 30, 2012 we recognized an income tax benefit of $4.0 million as a result of the deferred tax liability decreasing from $25.9 million at June 30, 2012 to $21.9 million at September 30, 2012.  For the three months ended September 30, 2011, there was no income tax expense or benefit recognized as we had a full valuation allowance on our U.S. and Canadian net deferred tax assets.

Net income.  Our net income was $3.5 million for the three months ended September 30, 2012, as compared to $30.8 million for the three months ended September 30, 2011. Our third quarter 2012 net income was negatively impacted by our loss on commodity price risk management activities, increased DD&A, G&A, and interest expense.  However, our net income was positively impacted by the increase in revenue and the income tax benefit recognized.

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Nine months ended September 30, 2012 Compared to Nine months ended September 30, 2011

Oil sales revenues.  Oil sales revenues increased by $203.4 million to $266.0 million for the nine months ended September 30, 2012, as compared to oil sales of $62.6 million for the same period in 2011. Our oil sales volume increased 344% to 3,209.8 MBbls for the nine months ended September 30, 2012, as compared to 722.4 MBbls for the same period in 2011. The average price we realized on the sale of our oil was $82.87 per barrel in the 2012 period compared to $86.65 per barrel in 2011. The volume increase is due to the development of our Bakken properties as well as the October 2011 and January 2012 property acquisitions.  Of the 2,487.4 MBbls increase in sales volume, 580.0 MBbls is related to producing wells acquired in these acquisitions and 1,907.4 MBbls is attributed to our ongoing development of our legacy properties and the acquired undeveloped acreage.  Overall, 101.3% of the increase in oil sales revenue was attributed to increased volumes and negative 1.3% was attributed to the decrease in crude oil prices received.

Natural gas sales revenues.  Natural gas sales revenues increased by $9.4 million to $11.8 million for the nine months ended September 30, 2012, as compared to natural gas sales revenues of $2.4 million for the same period in 2011. Natural gas sales volumes increased 674% to 2,201.1 MMcf for the nine months ended September 30, 2012 compared to 284.3 MMcf for the same period in 2011. The average price we realized on the sale of our natural gas was $5.38 per Mcf in the 2012 period compared to $8.39 per Mcf in 2011.  Overall, 109.1% of the increase in natural gas sales revenue was attributed to increased volumes and negative 9.1% was attributed to the decrease in natural gas prices received. The volume increase is due to the development of our Bakken properties as well as the October 2011 and January 2012 acquisitions.  Of the 1,916.8 MMcf increase in sales volume, 480.7 MMcf is related to producing wells acquired in these acquisitions and 1,436.1 MMcf is attributed to our ongoing development of our legacy properties and acquired undeveloped acreage.  Although gas from certain 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.  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 production expense increased by $44.0 million to $57.5 million for the nine months ended September 30, 2012 as compared to $13.5 million for the same period in 2011. The increase is due to a $22.3 million increase in production taxes, a $16.0 million increase in lease operating expenses and a $5.7 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 in which we participate in. On a per unit basis, LOE decreased from $7.46 per barrel sold in 2011 to $6.06 per barrel sold 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.  Availability of both trucking and third party disposal facilities has improved, which has decreased our LOE on a per unit basis.

To further reduce water disposal costs, in 2012, we have drilled water disposal wells on several of our producing areas and are constructing water gathering systems where appropriate. As we connect existing and future wells to these water gathering systems, we expect our LOE to continue to decrease on a per unit basis.

Depletion, depreciation, amortization and abandonment liability accretion (“DD&A”) expense.  Our depletion, depreciation, amortization and abandonment liability accretion expense increased by $89.2 million to $104.2 million for the nine months ended September 30, 2012, from $15.0 million for the same period in 2011. This increase is due to increased volumes sold in the first nine months of 2012 as sales volumes increased by approximately 2,806.9 MBOE over the same period in 2011. On a per unit basis, DD&A increased from $19.56 per barrel sold in the first nine months of 2011 to $29.13 per barrel sold in the first nine months of 2012. This increase in the 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 $12.1 million to $25.2 million for the nine months ended September 30, 2012, from $13.1 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 104 at September 30, 2012, from 60 at September 30, 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 nine months ended September 30, 2012, this expense was $7.9 million as compared to $3.5 million in 2011.

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Operating income.  Our operating income was approximately $91.0 million for the nine months ended September 30, 2012, as compared to approximately $23.3 million for the nine months ended September 30, 2011. This increase in operating income is attributed to our acquisitions in October 2011 and January 2012, our on-going successful completions of wells in our Bakken play which was partially offset by the decline in crude oil price from the first nine months of 2011 to the first nine months of 2012.

Gain (loss) on commodity price risk management activities.  Primarily due to the decrease in NYMEX crude oil prices at September 30, 2012 as compared to December 31, 2011, we incurred a total gain on our risk management activities of $40.6 million for the nine months ended September 30, 2012 compared to $14.0 million for the same period in 2011. This gain for the nine months ended September 30, 2012 is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. This gain was comprised of approximately $4.2 million of realized gains for transactions that were settled during the first nine months of 2012 and $36.4 million of unrealized gains for the mark-to-market of forward transactions. The unrealized gain is a non-cash adjustment for the value of our risk management transactions at September 30, 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 nine months ended September 30, 2012, we recognized interest expense of approximately $14.6 million, as compared to interest expense of $677,000 for the same period in 2011. Included in interest expense was $2.1 million and $677,000 in amortization of deferred financing costs for the nine months ended September 30, 2012 and 2011, respectively.  Additionally, we capitalized interest costs of $35.7 million and $3.8 million for the nine months ended September 30, 2012 and 2011, respectively.

Income tax expense (benefit).  As discussed in Note 5—Income Taxes under Item 1 in this Quarterly Report, through March 31, 2012, we had a full valuation allowance against our U.S. and Canada net deferred tax assets.  During the second quarter of 2012, we concluded that it was appropriate to reverse the U.S. valuation allowance, but retained a full valuation allowance on our Canadian net deferred tax assets.  We recognized a net deferred tax liability and income tax expense of $21.9 million as of September 30, 2012 and for the nine months then ended, respectively.  For the nine months ended September 30, 2011, there was no income tax expense or benefit recognized as we had a full valuation allowance on our U.S. and Canadian net deferred tax assets.

Net income.  Our net income was $98.3 million for the nine months ended September 30, 2012, as compared to $37.6 million for the nine months ended September 30, 2011. Our net income for the nine months ended September 30, 2012 was positively impacted by our gain on commodity price risk management activities and increases in revenue.  However, net income was negatively impacted by increased DD&A, G&A, interest expense, and income tax expense.

Commitments and Contingencies

For a discussion of our commitments and contingencies, please refer to Note 11—Commitments and Contingencies under item 1 in this Quarterly Report, which is incorporated herein by reference.

Off Balance Sheet Arrangements

The Company did not have any off balance sheet arrangements, as such term is defined in Item 303(a)(4)(ii) of Regulation S-K, at September 30, 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, which summary is qualified by the updates set forth below.  The updated disclosures set forth below have been included solely to clarify our actual treatment with respect to the applicable topics and do not reflect any change in accounting treatment relating thereto.

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Impairment of Oil and Gas Properties

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, impairment would be recognized.

Wells in Progress

Wells in progress represent the costs associated with wells that have not reached total depth or been completed as of period end. These costs are related to wells that are classified as both proved and unproved. Costs related to wells that are classified as proved are included in the depletion base.  Costs associated with wells that are classified as unproved are excluded from the depletion base.  The costs for unproved wells are then transferred to proved property when proved reserves are determined. The costs then become subject to depletion.

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 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.

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.

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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 four counterparties, and the Company is a guarantor of Kodiak Oil & Gas (USA) Inc. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparties. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

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

The Company’s commodity derivative contracts as of September 30, 2012 are summarized below:

Collars	Quantity (Bbl/d)	Strike Price ($/Bbl)
Oct 1, 2012—Dec 31, 2012	400	$70.00 - $95.56
Oct 1, 2012—Dec 31, 2012	230	$85.00 - $117.73
Oct 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	10,010	$98.38
2013 Total/Average	11,105	$95.84
2014 Total/Average	2,800	$91.86
2015 Total/Average	1,625	$87.13

(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 6—Commodity Derivative Instruments under Item 1 in this Quarterly Report.

Interest Rate Risk

At September 30, 2012, we had $800 million 8.125% Senior Notes outstanding due December 1, 2019, all of which has fixed rate interest.

In addition, as of September 30, 2012, we had a $375.0 million borrowing base under our credit facility, of which $115.0 million was drawn at September 30, 2012. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at September 30, 2012 under our credit facility of $375.0 million, a 1.0% increase in interest rates would result in additional annualized interest expense of approximately $3.8 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.

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ITEM 4.  CONTROLS AND PROCEDURES

Management, with the participation of our President and Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of September 30, 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 President and 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.

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
10.1	Sixth Amendment to Amended and Restated Credit Agreement among Kodiak Oil & Gas (USA) Inc.; as Borrower, Wells Fargo Bank, N.A., as Administrative Agent, and The Lenders Signatory Thereto, dated as of October 15, 2012
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.
November 1, 2012	/s/ LYNN A. PETERSON
	Lynn A. Peterson President and Chief Executive Officer
November 1, 2012	/s/ JAMES P. HENDERSON
	James P. Henderson Chief Financial Officer (principal financial and accounting officer)

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