Kodiak Oil & Gas (KOG) 10-Q 2013 Q2 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 June 30, 2013

Commission file number: 001-32920

(Exact name of registrant as specified in its charter)

Yukon Territory(State or other jurisdiction ofincorporation or organization)	N/A(I.R.S. EmployerIdentification No.)
1625 Broadway, Suite 250
Denver, Colorado 80202	(303) 592-8075
(Address of principal executive offices)	(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 (§ 232.405 of this chapter) 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 the definitions of “large accelerated filer", "accelerated filer", and "smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x Accelerated filer o Non-accelerated filer o(Do not check if asmaller reporting company) Smaller reporting company o

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

265,566,224 shares. no par value, of the Registrant’s common stock were issued and outstanding as of July 31, 2013

KODIAK OIL & GAS CORP.

INDEX

PART I - FINANCIAL INFORMATION	3
ITEMS 1. FINANCIAL STATEMENTS (UNAUDITED)	3
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	20
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	32
ITEM 4. CONTROLS AND PROCEDURES	34
PART II - OTHER INFORMATION	35
ITEM 1. LEGAL PROCEEDINGS	35
ITEM 1A. RISK FACTORS	35
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	35
ITEM 3. DEFAULTS UPON SENIOR SECURITIES	35
ITEM 4. MINE SAFETY DISCLOSURES	35
ITEM 5. OTHER INFORMATION	35
ITEM 6. EXHIBITS	36
SIGNATURES	37

2

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

	June 30, 2013			December 31, 2012
ASSETS
Current Assets:
Cash and cash equivalents	$	14,072		$	24,060
Accounts receivable
Trade	37,821			35,565
Accrued sales revenues	66,910			59,875
Commodity price risk management asset	4,162			10,864
Inventory, prepaid expenses and other	20,020			17,210
Total Current Assets	142,985			147,574
Oil and gas properties (full cost method), at cost:
Proved oil and gas properties	2,575,580			2,007,442
Unproved oil and gas properties	412,035			457,888
Equipment and facilities	27,190			20,954
Less-accumulated depletion, depreciation, amortization, and accretion	(409,105		)	(290,094		)
Net oil and gas properties	2,605,700			2,196,190
Cash held in escrow	51,000			—
Commodity price risk management asset	10,025			2,850
Property and equipment, net of accumulated depreciation of $1,456 at June 30, 2013 and $1,113 at December 31, 2012	2,288			1,846
Deferred financing costs, net of amortization of $20,058 at June 30, 2013 and $17,995 at December 31, 2012	31,347			25,176
Total Assets	$	2,843,345		$	2,373,636
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	198,042		$	190,596
Accrued interest payable	14,670			6,090
Commodity price risk management liability	1,337			304
Total Current Liabilities	214,049			196,990
Noncurrent Liabilities:
Credit facility	291,000			295,000
Senior notes, net of accumulated amortization of bond premium of $695 at June 30, 2013 and $378 at December 31, 2012	1,155,305			805,622
Commodity price risk management liability	—			4,288
Deferred tax liability, net	65,700			26,800
Asset retirement obligations	11,122			9,064
Total Noncurrent Liabilities	1,523,127			1,140,774
Total Liabilities	1,737,176			1,337,764
Stockholders’ Equity:
Common stock—no par value; unlimited authorized
Issued and outstanding: 265,566,224 shares as of June 30, 2013 and 265,273,314 shares as of December 31, 2012	1,015,281			1,008,678
Retained earnings	90,888			27,194
Total Stockholders’ Equity	1,106,169			1,035,872
Total Liabilities and Stockholders’ Equity	$	2,843,345		$	2,373,636

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)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
Revenues:
Oil sales	$	163,369		$	82,390		$	319,212		$	159,204
Gas sales	10,109			3,378			19,316			6,500
Total revenues	173,478			85,768			338,528			165,704
Operating expenses:
Oil and gas production	37,531			17,200			73,522			34,500
Depletion, depreciation, amortization and accretion	62,409			34,189			119,794			60,484
General and administrative	10,326			8,142			20,628			16,040
Total operating expenses	110,266			59,531			213,944			111,024
Operating income	63,212			26,237			124,584			54,680
Other income (expense):
Gain on commodity price risk management activities	22,667			95,572			6,923			72,232
Interest income (expense), net	(15,785		)	(3,541		)	(29,595		)	(8,168		)
Other income	256			724			682			1,992
Total other income (expense)	7,138			92,755			(21,990		)	66,056
Income before income taxes	70,350			118,992			102,594			120,736
Income tax expense	26,100			25,920			38,900			25,920
Net income	$	44,250		$	93,072		$	63,694		$	94,816
Earnings per common share:
Basic	$	0.17		$	0.35		$	0.24		$	0.36
Diluted	$	0.17		$	0.35		$	0.24		$	0.35
Weighted average common shares outstanding:
Basic	265,434,514			263,576,093			265,381,746			263,118,367
Diluted	267,906,171			267,558,510			267,851,680			267,419,601

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)

	For the Six Months Ended June 30,
	2013			2012
Cash flows from operating activities:
Net income	$	63,694		$	94,816
Reconciliation of net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	119,794			60,484
Amortization of deferred financing costs and debt premium	1,746			1,257
Unrealized gain on commodity price risk management activities, net	(3,728		)	(73,084		)
Stock‑based compensation	7,225			5,090
Deferred income taxes	38,900			25,920
Changes in current assets and liabilities:
Accounts receivable‑trade	(2,154		)	581
Accounts receivable‑accrued sales revenue	(7,035		)	(16,996		)
Prepaid expenses and other	(186		)	1,822
Accounts payable and accrued liabilities	6,068			11,010
Accrued interest payable	8,580			(480		)
Cash held in escrow	—			3,343
Net cash provided by operating activities	232,904			113,763
Cash flows from investing activities:
Acquired oil and gas properties and facilities	—			(588,420		)
Oil and gas properties	(520,312		)	(332,311		)
Equipment, facilities and other	(7,020		)	(6,774		)
Tubular goods	(2,298		)	(7,576		)
Cash held in escrow	(51,000		)	30,000
Net cash used in investing activities	(580,630		)	(905,081		)
Cash flows from financing activities:
Borrowings under credit facility	354,875			85,000
Repayments under credit facility	(358,875		)	(185,000		)
Proceeds from the issuance of senior notes	350,000			156,000
Proceeds from the issuance of common shares	490			1,245
Purchase of common shares	(518		)	—
Cash held in escrow	—			670,615
Debt and share issuance costs	(8,234		)	(4,650		)
Net cash provided by financing activities	337,738			723,210
Decrease in cash and cash equivalents	(9,988		)	(68,108		)
Cash and cash equivalents at beginning of the period	24,060			81,604
Cash and cash equivalents at end of the period	$	14,072		$	13,496
Supplemental cash flow information:
Oil & gas property accrual included in accounts payable and accrued liabilities	$	155,032		$	71,097
Oil & gas property acquired through common stock	$	—		$	49,798
Cash paid for interest	$	35,190		$	37,810
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. is a public company listed for trading on the New York Stock Exchange under the symbol: “KOG”. The Company's corporate headquarters are located in Denver, Colorado, USA. The Company is an independent energy company engaged in the exploration, exploitation, development, acquisition and production of crude oil and natural gas entirely in the Rocky Mountain region of the United States. Kodiak Oil & Gas Corp. was incorporated (continued) in the Yukon Territory on September 28, 2001. The Company and its wholly-owned subsidiaries, Kodiak Oil & Gas (USA) Inc., KOG Finance, LLC, KOG Oil & Gas, ULC and Kodiak Williston, LLC, are collectively referred to herein as “Kodiak” or the “Company”.

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 subsidiaries. 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 2012 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 2012 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 its 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 its estimates are reasonable.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-11 (“ASU 2011-11”), Balance Sheet: Disclosures about Offsetting Assets and Liabilities which applies to certain items in the statement of financial position (balance sheet), and was further clarified in January 2013 by ASU 2013-01, Balance Sheet: Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarified the scope of ASU 2011-11 to derivative instruments, repurchase agreements and securities lending transactions. The effective date for the amendments is for annual periods beginning after January 1, 2013, and interim periods within those annual periods. ASU 2011-11 requires disclosures of the gross and net amounts for items eligible for offset in the balance sheet. The Company records its derivative financial instruments on a net basis by contract. The adoption of this standard had no impact on the Company’s financial position or results of operations, but did require enhanced disclosures regarding derivative instruments. Please refer to Note 6—Commodity Derivative Instruments for the enhanced disclosures.

6

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.

Note 3—Acquisitions

July 2013 Acquisition

On July 12, 2013, the Company's subsidiary, Kodiak Williston LLC, acquired an unaffiliated oil and gas company’s interests in approximately 42,000 net acres of Williston Basin leaseholds, and related producing properties located primarily in McKenzie and southern Williams Counties, North Dakota, along with various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract (the "July 2013 Acquisition") . The seller received aggregate consideration of approximately $731.8 million in cash. The effective date for the acquisition was March 1, 2013, with purchase price adjustments calculated as of the closing date on July 12, 2013. The acquisition provided strategic additions adjacent to the Company's core project area. Pursuant to the purchase and sale agreement, the Company deposited $51.0 million into escrow in June 2013, which was credited to the purchase price at the closing of the acquisition. The $51.0 million deposit is recorded on the balance sheet under long term cash held in escrow. The acquisition contributed no revenue to Kodiak for the three and six months ended June 30, 2013 and 2012. Transaction costs related to the acquisition incurred through June 30, 2013 were approximately $160,000 and are recorded in the statement of operations within the general and administrative expenses line item. The Company estimates an additional $80,000 of transaction costs will be incurred in the second half of 2013.

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 July 12, 2013. Management has not had the opportunity to complete its assessment of the fair values of assets acquired and liabilities assumed. Accordingly, the allocation will change as additional information becomes available and is assessed by the Company, and the impact of such changes may be material. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed (in thousands):

Purchase Price	July 12, 2013
Consideration Given
Cash from credit facility	$	731,785
Total consideration given	$	731,785
Allocation of Purchase Price
Proved oil and gas properties	$	388,602
Unproved oil and gas properties	313,688
Total fair value of oil and gas properties acquired	$	702,290
Working capital	$	30,910
Asset retirement obligation	(1,415		)
Fair value of net assets acquired	$	731,785
Working capital acquired was estimated as follows:
Accounts receivable	$	65,322
Accrued liabilities	(34,412		)
Total working capital	$	30,910

7

Pro Forma Financial Information

The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired in July 2013 for the for the three and six months ended June 30, 2013 and 2012 as if the acquisition had occurred on January 1, 2012 (in thousands, except per share data). For purposes of the pro forma it was assumed that the credit facility was utilized on January 1, 2012. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $11.6 million and $22.5 million for the three and six months ended June 30, 2013, respectively, as compared to $4.1 million and $4.8 million for the three and six months ended June 30, 2012, respectively. The pro forma information includes the effects of adjustments for amortization of financing costs of $204,000 and $408,000 for the three and six months ended June 30, 2013, respectively, as compared to $204,000 and $408,000 for the three and six months ended June 30, 2012, respectively. The pro forma information includes the effects of the incremental interest expense on acquisition financing of $2.2 million and $4.8 million for the three and six months ended June 30, 2013, respectively, as compared to $4.4 million and $9.6 million for the three and six months ended June 30, 2012, respectively. The pro forma financial information includes total capitalization of interest expense of $9.8 million and $20.3 million for the three and six months ended June 30, 2013, respectively as compared to $12.2 million and $24.1 million for the three and six months ended June 30, 2012, respectively. The pro forma information includes the effects of adjustments for income tax expense of $5.9 million and $13.5 million for the three and six months ended June 30, 2013, respectively, as compared to $1.1 million and for both the three and six months ended June 30, 2012, respectively. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Operating revenues	$	213,976	$	101,188	$	421,506	$	185,834
Net income	$	53,924	$	94,802	$	85,388	$	94,297
Earnings per common share
Basic	$	0.20	$	0.36	$	0.32	$	0.36
Diluted	$	0.20	$	0.35	$	0.32	$	0.35

Note 4—Long-Term Debt

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

	June 30, 2013		December 31, 2012
Credit Facility due April 2018	$	291,000	$	295,000
2019 Notes due December 2019	800,000		800,000
Unamortized Premium on 2019 Notes	5,305		5,622
2021 Notes due January 2021	350,000		—
Total Long-Term Debt	$	1,446,305	$	1,100,622
Less: Current Portion of Long-Term Debt	—		—
Total Long-Term Debt, Net of Current Portion	$	1,446,305	$	1,100,622

8

Credit Facility

Kodiak Oil & Gas (USA) Inc. (the “Borrower”), a wholly-owned subsidiary of Kodiak Oil & Gas Corp., has in place a credit facility with a syndicate of banks. As of June 30, 2013, the maximum credit available under the credit facility was $1.5 billion with a borrowing base of $650.0 million and aggregate commitments of $550.0 million. Redetermination of the borrowing base occurs semi-annually, on April 1 and October 1. Additionally, the Company may elect a redetermination of the borrowing base one time during any six month period. On July 12, 2013, in conjunction with the July 2013 Acquisition, the Company entered into an amendment with its lenders increasing the borrowing base on its credit facility to $1.1 billion. The credit facility matures on April 2, 2018. In connection with the issuance of the 2022 Notes (as discussed below), the lenders under the Company’s credit facility agreed to waive provisions that would have otherwise resulted in a reduction in the borrowing base under the credit facility upon consummation of the offering.

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 credit facility. This additional percentage is referred to as the “Applicable Margin” and varies depending on the type of loan. As of the date of this filing, the Applicable Margin for the ABR loans is a sliding scale of 0.50% to 1.50%, depending on borrowing base usage. The Applicable Margin on the adjusted LIBO rate is a sliding scale of 1.50% to 2.50%, 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 facility) as of 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	1.50	%	1.75	%	2.00	%	2.25	%	2.50	%
ABR Loans	0.50	%	0.75	%	1.00	%	1.25	%	1.50	%
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 into 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 to 1.0 and to maintain on the last day of each quarter, a ratio of total debt to EBITDAX of not greater than 4.0 to 1.0 at the end of each fiscal quarter. The Company was in compliance with all financial covenants under the credit facility as of June 30, 2013, and through the filing of this report.

As of June 30, 2013, the Company had $291.0 million in outstanding borrowings under the credit facility and as such, the available credit under the credit facility at that date was $259.0 million. Subsequent to June 30, 2013, the Company made additional borrowings to finance the July 2013 Acquisition and fund capital expenditures. Additionally, all of the net proceeds from the 2022 Notes (as further discussed below) issued in July 2013 were used to repay borrowings on the credit facility. The Company's outstanding balance as of July 30, 2013 under the credit facility was $608.0 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. Borrowings under the credit facility are also guaranteed by the Company's subsidiaries other than the Borrower. 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.

Second Lien Credit Agreement

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

9

Senior Notes

In November 2011, the Company issued at par $650.0 million principal amount of 8.125% Senior Notes due December 1, 2019 and in May 2012, the Company issued at a price of 104.0% of par an additional $150.0 million aggregate principal amount of 8.125% Senior Notes due December 1, 2019 (the “2019 Notes”). The 2019 Notes bear an annual interest rate of 8.125% and are due December 1, 2019. The interest on the 2019 Notes is payable on June 1 and December 1 of each year. The issuance of the 2019 Notes resulted in aggregate net proceeds of approximately $784.2 million after deducting discounts and fees. The Company used the proceeds from the 2019 Notes to fund its acquisition program and repay outstanding borrowings under its credit facility and second lien credit agreement and for general corporate purposes.

In January 2013, the Company issued at par $350.0 million principal amount of 5.50% Senior Notes due January 15, 2021 (the "2021 Notes"). The 2021 Notes bear an annual interest rate of 5.50% and are due January 15, 2021. The interest on the 2021 Notes is payable on January 1 and July 1 of each year. The Company received net proceeds of approximately $343.1 million after deducting discounts and fees. All of the net proceeds from the 2021 Notes were used to repay borrowings on the Company's credit facility.

In July 2013, the Company issued at par $400.0 million principal amount of 5.50% Senior Notes due February 1, 2022 (the "2022 Notes" and together with the 2019 Notes and 2021 Notes, the "Senior Notes"). The 2022 Notes bear an annual interest rate of 5.50% and are due February 1, 2022. The interest on the 2022 Notes is payable on February 1 and August 1 of each year commencing on February 1, 2014. The Company received net proceeds of approximately $392.5 million after deducting discounts and fees. All of the net proceeds from the 2022 Notes were used to repay borrowings on the Company's credit facility.

The 2019 Notes and 2021 Notes were issued under separate indentures among the Company, Kodiak Oil & Gas (USA) Inc., as guarantor, U.S. Bank National Association, as trustee, and Computershare Trust Company of Canada, as Canadian trustee (the “2019 Indenture” and the “2021 Indenture”, respectively). The 2022 Notes were issued under an indenture among the Company, Kodiak Oil & Gas (USA) Inc., Kodiak Williston, LLC and KOG Finance, LLC (collectively, the “Guarantors”), U.S. Bank National Association, as trustee, and Computershare Trust Company of Canada, as Canadian trustee (the “2022 Indenture”, and together with the 2019 Indenture and the 2021 Indenture, the “Indentures”). In July 2013, the Guarantors entered into Supplemental Indentures to the 2019 Indenture and 2021 Indenture to guarantee the 2019 Notes and 2021 Notes. The Indentures contain affirmative and negative covenants that, among other things, limit the Company's and the Guarantors' 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 Indentures also contain 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 the Indentures as of June 30, 2013, and through the filing of this report.

The 2019 Notes are redeemable by the Company at any time on or after December 1, 2015, the 2021 Notes are redeemable by the Company at any time on or after January 15, 2017, and the 2022 Notes are redeemable by the Company at any time on or after August 1, 2017, in each case, at the redemption prices set forth in the indentures. Further, the 2019 Notes are redeemable by the Company prior to December 1, 2015, the 2021 Notes are redeemable by the Company prior to January 15, 2017, and the 2022 Notes are redeemable by the Company prior to August 1, 2017, in each case, at the redemption prices plus a “make-whole” premium set forth in the Indentures. The Company is also entitled to redeem up to 35% of the aggregate principal amount of the 2019 Notes before December 1, 2014, up to 35% of the aggregate principal amount of the 2021 Notes before January 15, 2016, and up to 35% of the aggregate principal amount of the 2022 Notes before August 1, 2016, with net proceeds that the Company raises in equity offerings at a redemption price equal to 108.125% of the principal amount of the 2019 Notes being redeemed and 105.5% of the principal amount of the 2021 Notes being redeemed and 105.5% of the principal amount of the 2022 Notes being redeemed, plus, in each case, accrued and unpaid interest. If the Company undergoes a change of control, it may redeem all, but not less than all, of the Senior Notes at a redemption price equal to 101% of the principal amount of the Senior Notes redeemed plus accrued and unpaid interest. The Company may redeem the Senior Notes if, as a result of changes in applicable law, it is required to pay additional amounts related to tax-withholdings, at a price equal to 100% of the Senior Notes plus accrued and unpaid interest. The Company must offer to purchase the Senior Notes if it sells assets under certain circumstances.

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On November 16, 2012, the Company closed a registered exchange offer with respect to the 2019 Notes pursuant to which all of the holders of the privately placed 2019 Notes exchanged their notes for SEC-registered 2019 Notes. With respect to the 2021 Notes and 2022 Notes, the Company must either (1) file an exchange offer registration statement to allow the holders to exchange the Senior Notes for SEC-registered notes and (2) file, under certain circumstances, a shelf registration statement to cover resales of the 2021 Notes and/or the 2022 Notes. If the Company were to fail to complete the registered exchange offer or the shelf registration statement were not to be declared effective within specified time periods, the Company would be required to pay liquidated damages by way of additional interest on the 2021 Notes and/or the 2022 Notes.

Deferred Financing Costs

As of June 30, 2013, the Company had deferred financing costs of $31.3 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 facility and Senior Notes. For the three and six months ended June 30, 2013, the Company recorded amortization expense of $1.0 million and $2.1 million, respectively, as compared to $690,000 and $1.3 million for the three and six months ended June 30, 2012, respectively.

Interest Incurred On Long-Term Debt

For the three and six months ended June 30, 2013, the Company incurred interest expense on long-term debt of $22.4 million and $43.8 million, respectively, as compared to $15.0 million and $28.5 millions for the three and six months ended June 30, 2012, respectively. Of the total interest incurred, the Company capitalized interest costs of $7.4 million and $15.9 million for the three and six months ended June 30, 2013, respectively, as compared to $12.0 million and $24.5 million for the three and six months ended June 30, 2012, respectively. Additionally, for the three and six months ended June 30, 2013, interest expense was reduced for the amortization of the bond premium in the amounts of $160,000 and $317,000, respectively, as compared to $73,000 for both the three and six months ended June 30, 2012, respectively.

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; 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. 

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. Additionally, the Company has the ability and intends to indefinitely reinvest the undistributed earnings of Kodiak Oil & Gas (USA) Inc. with the exception of a de minimis amount of Canadian general and administrative expenses paid by Kodiak Oil & Gas (USA) Inc. on behalf of Kodiak Oil & Gas Corp.

The Company recognized income tax expense of $26.1 million and $38.9 million for the three and six months ended June 30, 2013, respectively. The Company recognized income tax expense of $25.9 million for both the three and six months ended June 30, 2012.

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Accounting for Uncertainty in Income Taxes

As of June 30, 2013, the Company believes that it has no liability for uncertain tax positions. If the Company were to determine there were any uncertain tax positions, the Company would recognize the liability and related interest and penalties within income tax expense. As of June 30, 2013, 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 the Company's future oil production. A collar requires the Company to pay the counterparty if the settlement price is above the ceiling price and requires the counterparty to pay the Company if the settlement price is below the floor price. A swap requires the Company to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay the Company if the settlement price is less than the strike price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The 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 eight counterparties. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity price risk management assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of income. The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

The Company’s commodity derivative contracts as of June 30, 2013 are summarized below:

Collars	Basis(1)	Quantity (Bbl/d)	Strike Price ($/Bbl)
Jul 1, 2013—Dec 31, 2013	NYMEX	500	$85.00 - $117.00
Jul 1, 2013—Dec 31, 2015	NYMEX	300 - 425	$85.00 - $102.75
Swaps	Basis (1)	Average Quantity (Bbl/d)	Average Swap Price ($/Bbl)
2013 Total	NYMEX	18,105	$95.64
2014 Total	NYMEX	14,800	$91.67
2015 Total	NYMEX	1,625	$87.13

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Subsequent to June 30, 2013, the Company entered into additional commodity derivative contracts as summarized below:

Contract Type	Basis (1)	Quantity (Bbl/d)	Swap Price ($/Bbl)	Term
Swap	NYMEX	500	$96.63	Jul 1, 2013—Dec 31, 2013
Swap	NYMEX	1,000	$96.78	Jul 1, 2013—Dec 31, 2013
Swap	NYMEX	500	$96.70	Jul 1, 2013—Dec 31, 2013
Swap	NYMEX	500	$91.00	Jan 1, 2014—Dec 31, 2014
Swap	NYMEX	500	$91.00	Jan 1, 2014—Dec 31, 2014

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

The following tables detail the fair value of the Company's derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the consolidated balance sheet (in thousands):

		As of June 30, 2013
Underlying Commodity	Location on Balance Sheet	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Consolidated Balance Sheet
Crude oil derivative contract	Current assets	$	10,629	$	(6,467	)	$	4,162
Crude oil derivative contract	Noncurrent assets	$	11,478	$	(1,453	)	$	10,025
Crude oil derivative contract	Current liabilities	$	7,804	$	(6,467	)	$	1,337
Crude oil derivative contract	Noncurrent liabilities	$	1,452	$	(1,452	)	$	—

		As of December 31, 2012
Underlying Commodity	Location on Balance Sheet	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Consolidated Balance Sheet
Crude oil derivative contract	Current assets	$	16,911	$	(6,047	)	$	10,864
Crude oil derivative contract	Noncurrent assets	$	5,455	$	(2,605	)	$	2,850
Crude oil derivative contract	Current liabilities	$	6,352	$	(6,048	)	$	304
Crude oil derivative contract	Noncurrent liabilities	$	6,893	$	(2,605	)	$	4,288

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2013		2012		2013		2012
Unrealized gain on oil contracts	$	20,910	$	91,700	$	3,728	$	73,084
Realized gain (loss) on oil contracts	1,757		3,872		3,195		(852		)
Gain on commodity price risk management activities	$	22,667	$	95,572	$	6,923	$	72,232

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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. The Company's asset retirement obligation is summarized below (in thousands):

	For the Six Months Ended June 30,		For the Year Ended December 31, 2012
Balance beginning of period	$	9,064	$	3,627
Liabilities incurred or acquired	1,618		4,537
Liabilities settled	—		(58		)
Revisions in estimated cash flows	—		405
Accretion expense	440		553
Balance end of period	$	11,122	$	9,064

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:

• 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.

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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 June 30, 2013 by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at June 30, 2013 Using
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity price risk management asset	$	—	$	14,187	$	—	$	14,187
Financial Liabilities:
Commodity price risk management liability	$	—	$	1,337	$	—	$	1,337

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 June 30, 2013 and December 31, 2012, 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.

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 2019 Notes and the 2021 Notes was derived from available market data. This disclosure (in thousands) does not impact our financial position, results of operations or cash flows.

	At June 30, 2013				At December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Credit facility	$	291,000	$	291,000	$	295,000	$	295,000
2019 Notes	$	805,305	$	868,000	$	805,622	$	890,000
2021 Notes	$	350,000	$	341,250	$	—	$	—

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Note 9—Share‑Based Payments

The Company has granted various equity-based awards 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 (as so amended, 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, 2013, the maximum number of shares issuable under the Plan, including those previously issued thereunder, was approximately 37.1 million shares.

Stock Options

Total compensation expense related to the stock options of $1.7 million and $3.7 million was recognized for the three and six months ended June 30, 2013, respectively, as compared to $1.6 million and $3.0 million for the three and six months ended June 30, 2012. As of June 30, 2013, 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 1.6 years.

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

	For the Six Months Ended June 30,			For the Year Ended December 31, 2012
Risk free rates	0.88 - 1.61%			0.78 - 1.48%
Dividend yield	—		%	—		%
Expected volatility	82.43 - 85.08%			85.23 - 90.25%
Weighted average expected stock option life	5.74 years			5.85 years
The weighted average fair value at the date of grant for stock options granted is as follows:
Weighted average fair value per share	$	6.30		$	6.58
Total options granted	1,191,400			1,159,500
Total weighted average fair value of options granted	$	7,505,820		$	7,629,510

A summary of the stock options outstanding is as follows:

	Number of Options		Weighted Average Exercise Price
Balance outstanding at January 1, 2013:	5,705,951		$	4.83
Granted	1,191,400		$	9.06
Canceled	(525,574	)	$	6.99
Exercised	(256,910	)	$	3.98
Balance outstanding at June 30, 2013:	6,114,867		$	5.51
Options exercisable at June 30, 2013:	3,923,600		$	4.01

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The following table summarizes information about stock options outstanding at June 30, 2013:

	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	5.5	$	0.36	241,000	5.5	$	0.36
$1.01-$2.00	547,448	0.9	$	1.18	547,448	0.9	$	1.18
$2.01-$3.00	739,830	6.1	$	2.37	715,830	6.1	$	2.35
$3.01-$4.00	1,178,377	3.5	$	3.46	1,178,377	3.5	$	3.46
$4.01-$5.00	147,000	7.8	$	4.47	68,000	7.6	$	4.39
$5.01-$6.00	232,000	8.0	$	5.58	125,000	7.9	$	5.54
$6.01-$7.00	771,112	7.1	$	6.44	491,112	6.7	$	6.44
$7.01-$8.00	322,000	8.9	$	7.51	97,000	8.3	$	7.39
$8.01-$9.00	644,000	8.9	$	8.67	115,000	8.4	$	8.71
$9.01-$10.53	1,292,100	9.2	$	9.44	344,833	8.4	$	9.81
	6,114,867	6.4	$	5.51	3,923,600	5.0	$	4.01

The aggregate intrinsic value of both outstanding and vested options as of June 30, 2013 was $21.4 million, based on the Company’s June 30, 2013 closing common stock price of $8.89. This amount would have been received by the option holders had all option holders exercised their options as of that date. The total grant date fair value of the shares vested during the six months ended June 30, 2013 was $4.9 million.

Restricted Stock Units and Restricted Stock

Total compensation expense related to restricted stock units (“RSUs”) and restricted stock of $1.8 million and $3.5 million was recognized for the three and six months ended June 30, 2013, respectively, as compared to $1.1 million and $2.1 million for the three and six months ended June 30, 2012, respectively. As of June 30, 2013, there was $9.3 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.

As of June 30, 2013, there were 721,708 unvested performance based RSUs, 1,077,873 unvested performance based restricted stock shares and 58,500 unvested restricted stock shares with a combined weighted average grant date fair value of $8.93 per share. The total fair value vested during the six months ended June 30, 2013 was $74,000. A summary of the RSUs and restricted stock shares outstanding is as follows:

	Number of Shares		Weighted Average Grant Date Fair Value
Non-vested restricted stock and RSU's at January 1, 2013	1,829,581		$	8.93
Granted	36,000		$	8.85
Forfeited	—		$	—
Vested	(7,500	)	$	9.87
Non-vested restricted stock and RSU's at June 30, 2013	1,858,081		$	8.93

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Note 10—Earnings Per Share

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

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

The performance based restricted stock units and unexercised stock options are not participating securities, since these shares are not entitled to participate in dividends declared on common shares. The number of potentially dilutive shares attributable to the performance based restricted stock units is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the performance measurement period. Please refer to Note 9—Share‑Based Payments under the heading Restricted Stock Units and Restricted Stock for additional discussion.

The table below sets forth the computations of basic and diluted net income per share for the three and six months ended June 30, 2013 and 2012 (in thousands, except per share data):

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
Basic net income	$	44,250		$	93,072		$	63,694		$	94,816
Income allocable to participating securities	(6		)	(11		)	(9		)	(11		)
Diluted net income	$	44,244		$	93,061		$	63,685		$	94,805
Basic weighted average common shares outstanding	265,434,514			263,576,093			265,381,746			263,118,367
Effect of dilutive securities
Options to purchase common shares	4,348,767			5,855,040			4,529,767			6,244,040
Assumed treasury shares purchased	(2,522,963		)	(2,189,160		)	(2,672,983		)	(2,244,942		)
Unvested restricted stock units	645,853			316,537			613,150			302,136
Diluted weighted average common shares outstanding	267,906,171			267,558,510			267,851,680			267,419,601
Basic earnings per share	$	0.17		$	0.35		$	0.24		$	0.36
Diluted earnings per share	$	0.17		$	0.35		$	0.24		$	0.35

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 June 30,		For the Six Months Ended June 30,
	2013	2012	2013	2012
Anti-dilutive shares	1,766,100	959,500	1,585,100	570,500

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Note 11—Commitments and Contingencies

Lease Obligations

The Company leases office space in Denver, Colorado and Williston and Dickinson, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on October 31, 2016. The Williston and Dickinson, North Dakota leases expire on May 31, 2014 and December 31, 2014 respectively. Total rental commitments under non-cancelable leases for office space were $3.0 million at June 30, 2013. The future minimum lease payments under these non-cancelable leases are as follows: $450,000 in 2013, $930,000 in 2014, $860,000 in 2015, $770,000 in 2016, and $0 in 2017.

Drilling Rigs

As of June 30, 2013, the Company was subject to commitments on four of its six drilling rigs. Three of the contracts expire in 2013 and one expires in 2015. In the event of early termination under all of these contracts, the Company would be obligated to pay an aggregate amount of approximately $24.8 million as of June 30, 2013 as required under the varying terms of such contracts. Subsequent to June 30, 2013 as part of the July 2013 Acquisition, the Company assumed an additional 13 month drilling rig contract commencing on July 12, 2013. In the event of early termination under this contract, the Company would be obligated to pay an additional $7.9 million.

Pressure Pumping Services

As of June 30, 2013, 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 $12.0 million as of June 30, 2013.

Guarantees of the Senior Notes

As of June 30, 2013, the Company had issued $800.0 million of 2019 Notes and $350.0 million of 2021 Notes, all of which are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. In July 2013, Kodiak Williston, LLC and KOG Finance, LLC entered into Supplemental Indentures to the 2019 Indenture and the 2021 Indenture to guarantee the 2019 Notes and the 2021 Notes. Kodiak Oil & Gas Corp, as the parent company, has no independent assets or operations. The guarantees are full, unconditional and joint and several. Subsequent to June 30, 2013, the Company issued $400.0 million of 2022 Notes, all of which are guaranteed on a senior unsecured basis by our wholly-owned subsidiaries, Kodiak Oil & Gas (USA) Inc., Kodiak Williston, LLC and KOG Finance, LLC. The guarantees are full, unconditional, and joint and several. The Company's non-guarantor subsidiary, KOG Oil & Gas ULC has de minimis operations.

Under the Company’s credit facility and the Indentures, the Company and subsidiary guarantors are

subject to certain limitations on the ability of the subsidiary guarantors to transfer funds to the Company, including certain

limitations on dividends, distributions, redemptions, payments, investments, loans and advances. There are no other

restrictions on the ability of the company to obtain funds from its subsidiaries by dividend or loan (other than as

described in Note 4-Long-Term Debt). Finally, the 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 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 subsidiaries, Kodiak Oil & Gas (USA) Inc., Kodiak Williston, LLC and KOG Finance, LLC may guarantee. Any such guarantees are expected to be full, unconditional and joint and several. As stated above, the Company has no independent assets or operations, and, other than as described herein, there are no significant restrictions on the ability of the Company to receive funds from the Company's subsidiaries through dividends, loans, and advances or otherwise.

Other

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

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

Forward-Looking Statements

The information discussed in this quarterly report on Form 10-Q includes “forward‑looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed 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 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 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

We are an independent energy company focused on the exploration, exploitation, acquisition and production of crude oil and natural gas in the Rocky Mountain region of the United States. We have developed an oil and natural gas asset base of proved reserves, as well as a portfolio of development and exploratory drilling opportunities on high resource-potential leasehold. We intend to continue to expand our asset base by developing our current lands as well as evaluating and investing in core acquisitions.

                Our oil and natural gas reserves and operations are primarily concentrated in the Williston Basin of North Dakota, where the principal target of drilling is the Bakken Shale hydrocarbon system highlighted by production from the Middle Bakken member, located between two Bakken shales that serve as the source rock, and the Three Forks Formation, positioned immediately below the Lower Bakken Shale. As of June 30, 2013, we owned an interest in approximately 217,000 gross (154,000 net) acres in the Williston Basin and have an interest in 344 gross (156.6 net) producing wells in the Williston Basin.

Recent Developments

July 2013 Acquisition

On July 12, 2013, we closed our acquisition of core Williston Basin producing properties and undeveloped leasehold from an unaffiliated private oil and gas company ("July 2013 Acquisition").

The purchase price for the July 2013 Acquisition was $680.0 million. Post-closing adjustments were $51.8 million, including $30.9 million in working capital items and $20.9 million of cash flow adjustments to reflect the acquisition's March 1, 2013 effective date. The seller received aggregate consideration of approximately $731.8 million in cash.

Included in the acquisition are approximately 42,000 net leasehold acres and net production of approximately 5,500 barrels of oil equivalent per day located in McKenzie and Williams Counties, North Dakota.  The acquired leasehold includes 35 controlled drilling spacing units and is largely held by production. The southern Williams County lands, approximating 14,000 net acres, are adjacent to our core Polar area. An additional 25,000 net acres are located in McKenzie County to the west of our Koala and Smokey areas.

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Expanded Credit Facility and Senior Note Offering

We funded the July 2013 Acquisition through borrowings under our revolving credit facility. In connection with the acquisition and reflecting year-to-date completion activities, Kodiak and its lending group entered into an amendment to our credit facility to increase our borrowing base and aggregate commitments under our existing revolving credit facility to $1.1 billion. In connection with the issuance of the 2022 Notes (as discussed below), the lenders under our credit facility agreed to a waiver of provisions that provided for a reduction in the borrowing base under the credit facility upon consummation of the offering.

On July 26, 2013, we issued at par $400.0 million principal amount of 5.50% senior notes due February 1, 2022 (the “2022 Notes”). All of the net proceeds from this issuance were used to repay borrowings on our revolving credit facility. As of July 30, 2013, our current outstanding balance on our credit facility was $608.0 million.

Operational Update

During the second quarter of 2013, we completed 25 gross (21.5 net) operated wells and participated in the completion of 23 gross (2.5 net) non-operated wells.  Beginning in late May 2013, we operated with two full-time, 24-hour-per-day completion crews.  We intend to maintain the second completion crew through most of the remaining months of the year, as well as utilize a third completion crew on a temporary basis on the recently acquired lands.  We expect to complete 30 gross (25 net) operated wells during the third quarter.

We are presently operating a total of seven rigs.  Currently, three drilling rigs are operating in the Polar project area in southern Williams County, two rigs in the Smokey project area, one rig in the Koala project area in McKenzie County, and one rig in Dunn County.

Downspacing Tests

Our program to test 12 wells within a 1,280-acre drilling spacing unit (DSU) continues on schedule in the Polar and Smokey operating areas. All wells in the Polar project area in southern Williams County have been completed with eight of the wells on production.  In the Smokey project area in central McKenzie County, five wells have been completed and are on production and three wells were recently completed and are currently undergoing drill out procedures on the flow through plugs. The remaining four wells are on a separate drilling pad and drilling operations were recently completed. Infrastructure buildout has been completed in both areas.

Reserves Update

As of June 30, 2013, and pro forma for the July 2013 Acquisition, we have estimated proved reserves of 123.9 million barrels of oil and 120.7 billion cubic feet of natural gas, or 144.0 million barrels of oil equivalent (MMBOE).  The estimated present value discounted at 10% was $3.2 billion, before income tax effect. Our reserves quantities are comprised of 86% crude oil and 14% natural gas.  The June 30, 2013 proved reserves (prior to the addition of acquired reserves) reflect a 28% increase over year-end 2012's proved reserves of 94.8 MMBOE. Our legacy estimated reserves' quantities were audited by our independent reservoir engineering consultant, Netherland, Sewell & Associates, Inc. The reserves estimates for the July 2013 Acquisition were internally prepared by the Company. The following table summarizes our legacy and pro forma reserves (including our July 2013 Acquisition) as of June 30, 2013:

Reserve Category	% of Reserves		Oil (MBbls)	Gas (MMcf)	June 2013 MBOE	December 2012 MBOE	% Change		June 2013 PV-10 (Millions)
Legacy Assets
Proved Developed	46	%	47,262	48,442	55,336	43,136	28	%	$	1,669
Proved Undeveloped	54	%	56,823	54,233	65,862	51,647	28	%	956
Total Proved	100	%	104,085	102,675	121,198	94,783	28	%	$	2,625
Pro Forma for July 2013 Acquisition
Proved Developed	47	%	57,607	57,144	67,131	—	—	%	$	2,059
Proved Undeveloped	53	%	66,318	63,511	76,903	—	—	%	1,141
Total Proved - Pro Forma	100	%	123,925	120,655	144,034	—	—	%	$	3,200

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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 one rig is currently drilling, as well as other non-operated wells outside of the AMI. The following tables summarize the wells spud and completed during the three and six months ended June 30, 2013:

	For the Three Months Ended June 30, 2013
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	24.0	20.2	25.0	21.5
Non-operated wells	21.0	1.5	23.0	2.5
	45.0	21.7	48.0	24.0

	For the Six Months Ended June 30, 2013
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	45.0	37.2	45.0	36.1
Non-operated wells	43.0	4.9	43.0	6.6
	88.0	42.1	88.0	42.7

Liquidity and Capital Resources

2013 Capital Expenditures Budget

Our 2013 capital expenditures budget is subject to various factors, including market conditions, oil field services and equipment availability, commodity prices and drilling results. The following table summarizes our 2013 capital expenditures budget and our actual capital expenditures, including accruals, for the six months ended June 30, 2013:

			Six Months Ended
	Revised		June 30, 2013
	2013 Budget		Actual
Operated drilling and completion costs	$	825.0	$	414.6
Non-operated drilling and completion costs	140.0		73.8
Total drilling and completion costs	$	965.0	$	488.4
Salt water disposal wells and facilities	$	23.0	$	12.8
Leasehold acquisitions	12.0		3.6
Total capital expenditures	$	1,000.0	$	504.8
Asset retirement obligations	$	—	$	1.6
Capitalized interest	—		15.9
Total capitalized costs	$	1,000.0	$	522.3

We previously established a $775 million 2013 capital expenditure budget. In conjunction with the anticipated drilling and completion schedule in the second half of the year, the July 2013 Acquisition, combined with potential transactions affecting our working interest therein, we are increasing the estimated full year capital budget to a range of $950 million to $1 billion. This budget contemplates approximately 100 net wells being completed in 2013 as compared to 75 net wells being completed in our original budget.

During the six months ended June 30, 2013, we incurred capital expenditures of $504.8 million related to our oil field operations.  We are currently operating seven drilling rigs.  In late May 2013, we re-engaged our second completion crew, which we expect to continue to utilize throughout the remainder of 2013.

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As we move through 2013, we will continue to monitor the timing of our drilling and completion activities and, if necessary, we will adjust our plans accordingly based on crude oil pricing and service costs. We have a staggered rig termination schedule with multiple rigs terminating in 2013, allowing for an adjustment to our rig count to align with our cash flow and capital expenditure projections.

Average well costs continue to decline as the Williston Basin has experienced a significant increase in third party oil field services over the past year. As a result, as well as due to our gained efficiencies, our completed well costs have trended downward from approximately $10.6 million during the first quarter of 2013 to approximately $10.3 million in the second quarter of 2013, with current costs estimates below $10 million. We expect these costs to trend even lower as we move through 2013.

Sources of Capital

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 three years. This increase is directly related to our successful operations as we have developed our properties and, to a lesser extent, cash flows from acquired 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.

Credit facility. As of June 30, 2013, our maximum credit available under the credit facility was $1.5 billion with a borrowing base of $650.0 million and aggregate commitments of $550.0 million. As of June 30, 2013, we had available borrowings under the credit facility of $259.0 million.

As previously discussed, on July 12, 2013 in conjunction with the closing of the January 2013 Acquisition, we amended our credit facility to increase our borrowing base and aggregate commitments under our credit facility to $1.1 billion. As of July 30, 2013, we had $608.0 million outstanding under this credit facility, with available borrowings of $492.0 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 resulting from our ongoing drilling and completion activities. We are subject to restrictive covenants under the credit facility. For further details on our credit facility and Senior Notes please refer to Note 4-Long-Term Debt under Item 1 in this Quarterly Report.

Capital Requirements Outlook

We are dependent on our anticipated cash flows from operations and the expected borrowing availability under our credit facility to fund our capital expenditures budget, our obligations under our Senior Notes and other contractual commitments (please refer to Note 4-Long-Term Debt and Note 11-Commitments and Contingencies under Item 1 in this Quarterly Report for further details). While we expect such sources of capital to be sufficient for such purposes, there can be no assurance that we will achieve our anticipated future cash flows from operations, that credit will be available under our credit facility when needed, or that we would be able to complete alternative transactions in the capital markets, if needed. Our ability to obtain financing on commercially reasonable terms is dependent on a number of factors, many of which we cannot control, including changes in our credit rating, interest rates, market perceptions of us and the oil and natural gas exploration and production industry and tax burdens due to new tax laws.

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 development 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. 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. If we were not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our planned expenditures or restructure our operations (including reducing our rig count and sub-contracting our pressure pumping services agreement, either of which may in certain circumstances result in termination fees depending on the timing and requirements of the underlying agreements), we would be unable to implement our original exploration and drilling program, and we may be unable to service our debt obligation or satisfy our contractual obligations.

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Senior Notes

As of the date of this filing we have $800.0 million outstanding under our 8.125% Senior Notes due in December 2019, $350.0 million outstanding under our 5.50% Senior Notes due in January 2021 and $400.0 million outstanding under our 5.50% Senior Notes due February 2022. The annualized interest to be incurred under all of the Senior Notes is approximately $106.3 million.

In July 2013, we issued at par $400.0 million principal amount of 5.50% senior notes due February 1, 2022. All of the net proceeds from this issuance were used to repay borrowings on our credit facility. The interest on our 2022 Notes is payable on February 1 and August 1 of each year. In connection with the sale of our 2022 Notes, we entered into a registration rights agreement pursuant to which we agreed (1) to file an exchange offer registration statement to allow the holders to exchange the 2022 Notes for SEC-registered notes and (2) to file, under certain circumstances, a shelf registration statement to cover resales of the 2022 Notes. If we fail to complete the registered exchange offer or the shelf registration statement has not been declared effective within specified time periods, we will be required to pay liquidated damages by way of additional interest on the 2022 Notes.

For further discussion regarding our Senior Notes, please refer to Note 4-Long-Term Debt under Item 1 in this Quarterly Report.

Working Capital

As part of our cash management strategy, we frequently use available funds to reduce any balance on our credit facility. Because of this, we generally maintain low cash and cash equivalent balances. Since our principal source of operating cash flows (proved reserves to be produced in later periods) is not considered working capital, we often have low or negative working capital. Our working capital was a deficit of $71.1 million at June 30, 2013, as compared to a deficit of $49.4 million at December 31, 2012.

Registered Offerings

Historically, we have financed our operations, property acquisitions and other capital investments in part from the proceeds of offerings of our equity and debt securities. We may offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

Derivative Instruments

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

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Cash Flow Analysis

The following is a summary of our change in cash and cash equivalents for the six months ended June 30, 2013 and 2012 (in thousands):

	For the Six Months Ended June 30,						Period to period change
	2013			2012
Net cash provided by operating activities	$	232,904		$	113,763		$	119,141
Net cash used in investing activities	$	(580,630	)	$	(905,081	)	324,451
Net cash provided by financing activities	$	337,738		$	723,210		(385,472		)
Decrease in cash and cash equivalents	$	(9,988	)	$	(68,108	)	$	58,120

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 six months ended June 30, 2013 as compared to the six months ended June 30, 2012, our net cash provided by operating activities increased by $119.1 million, primarily from increased crude oil sales volumes attributable to our successful drilling and completions in our core Middle Bakken and Three Forks formations in the Williston Basin. Additionally, we utilize derivative instruments, as further discussed under the heading "Operating Results" below, to partially mitigate the impact of decreases in crude oil prices.

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 six months ended June 30, 2013 as compared to the six months ended June 30, 2012, our net cash used in investing activities decreased by $324.5 million. This decrease was attributed to our previously announced property acquisition completed in January 2012 ("2012 Acquisition"), which required $588.4 million in cash, which was partially offset by our significantly increased capital expenditures for drilling and completions during the six months ended June 30, 2013 as compared to the six months ended June 30, 2012. Also, offsetting this decrease was the $51.0 million deposit into escrow for our July 2013 Acquisition.

Net cash provided by financing activities. For the six months ended June 30, 2013 as compared to the six months ended June 30, 2012, our net cash provided by financing activities decreased by $385.5 million. This was a result of our receipt in January 2012 of $670.6 million in cash held in escrow, which was primarily used to finance our 2012 Acquisition and to repay in full the $100.0 million then outstanding on our second lien credit agreement, which was then terminated. Additionally, in the first six months of 2012, we issued $156.0 million of 2019 Notes. This decrease was partially offset by the issuance of our $350.0 million 2021 Notes in January 2013.

Our Properties

Williston Basin

Our Williston Basin acreage is located primarily in Dunn, McKenzie and Williams counties, of North Dakota. Our primary geologic targets are the Bakken Pool where our primary objective is the dolomitic, sandy interval between the two Bakken Shales at an approximate vertical depth of 10,300-11,300 feet and the second is the Three Forks, consisting of interbedded fine grain siltstones and dolomite, immediately below the lower Bakken shale. The Williston Basin also produces from many other formations including, but not limited to, the Mission Canyon, Nisku and Red River.

Our operations are in an area that we believe has higher reservoir pressure and a high degree of thermal maturity, which is prospective for both the Middle Bakken and multiple benches within the Three Forks. 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 (“EURs”) that range from 450 to over 1,000 MBOE.

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Our Leasehold

As of June 30, 2013, we had several hundred lease agreements representing approximately 251,000 gross and 164,000 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	14,727	4,105	9,009	1,799	23,736	5,904
Colorado	8,027	3,067	2,974	1,252	11,001	4,319
Williston Basin
Montana	—	—	3,951	1,861	3,951	1,861
North Dakota	89,187	61,112	123,565	90,553	212,752	151,665
Acreage Totals	111,941	68,284	139,499	95,465	251,440	163,749

(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.

As part of the July 2013 Acquisition, we acquired approximately 42,000 net acres of Williston Basin leaseholds located primarily in McKenzie and southern Williams Counties. The table above reflects our net acres prior to the July 2013 Acquisition.

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.

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, 2013	5,245	4,555
December 31, 2014	21,647	16,677
December 31, 2015	12,465	7,792
December 31, 2016	4,070	2,913
Total	43,427	31,937

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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, 2012, this field contained 99.8% of our total proved reserves. Our revenues are directly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The commodity prices are largely beyond our control and are difficult to predict. We have seen significant volatility in oil and natural gas prices in recent years. The following table discloses our oil and gas sales volumes from the Bakken field and from our other fields combined and in total, for the periods indicated:

	For the Three Months Ended June 30,		For the Six Months Ended June 30,
	2013	2012	2013	2012
Sales Volume (Bakken):
Oil (MBbls)	1,834.5	1,039.4	3,547.1	1,913.5
Gas (MMcf)	1,632.3	663.1	3,044.2	1,156.7
Sales Volume (Other):
Oil (MBbls)	3.6	4.5	7.2	8.9
Gas (MMcf)	8.7	6.0	17.2	16.6
Sales Volume (Total):
Oil (MBbls)	1,838.1	1,043.9	3,554.3	1,922.4
Gas (MMcf)	1,641.0	669.1	3,061.4	1,173.3
Sales volumes (MBOE)	2,111.6	1,155.4	4,064.5	2,118.0

Sales prices received, and costs incurred, presented on a per BOE basis, for the three and six months ended June 30, 2013 and 2012 are summarized in the following table:

	For the Three Months Ended March 31,				For the Six Months Ended June 30,
	2013		2012		2013		2012
Sales Price:
Oil ($/Bbls)	$	88.88	$	78.93	$	89.81	$	82.81
Gas ($/Mcf)(1)	$	6.16	$	5.05	$	6.31	$	5.54
BOE ($/BOE)	$	82.15	$	74.23	$	83.29	$	78.24
Commodity Price Risk Management Activities ($/Sales BOE):
Realized gain (loss)	$	0.83	$	3.35	$	0.79	$	(0.40	)
Production costs ($/Sales BOE):
Lease operating expenses	$	6.33	$	5.60	$	6.61	$	6.26
Production taxes	$	8.77	$	7.80	$	8.92	$	8.27
Gathering, transportation, marketing	$	2.67	$	1.49	$	2.56	$	1.76
DD&A	$	29.56	$	29.59	$	29.47	$	28.56
G&A	$	4.89	$	7.05	$	5.08	$	7.57
Stock‑based compensation	$	1.66	$	2.30	$	1.78	$	2.40

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

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Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

Oil sales revenues. Oil sales revenues increased by $81.0 million to $163.4 million for the three months ended June 30, 2013 as compared to oil sales of $82.4 million for the same period in 2012. In the second quarter of 2013, our crude oil sales averaged 20,199 barrels per day. Our oil sales volume increased 76.1% to 1,838.1 thousand barrels (“MBbls”) in the second quarter of 2013 as compared to 1,043.9 MBbls in the second quarter of 2012. The volume increase is due to the ongoing development of our Bakken properties. The average price we realized on the sale of our oil increased from $78.93 per barrel sold in the second quarter of 2012 to $88.88 per barrel sold in the second quarter of 2013. Overall, 87.2% of the increase in oil sales revenue was attributed to increased volumes and 12.8% was attributed to the increase in crude oil prices received.

Natural gas sales revenues. Natural gas revenues increased by $6.7 million to $10.1 million for the three months ended June 30, 2013 as compared to natural gas revenues of $3.4 million for the same period in 2012. Natural gas sales volumes increased by 971.9 million cubic feet ("MMcf") to 1,641.0 MMcf for the three months ended June 30, 2013. In the second quarter of 2013, our natural gas sales averaged 18.0 MMcf per day. The average price we realized on the sale of our natural gas was $6.16 per Mcf in the second quarter of 2013 compared to $5.05 per Mcf in the second quarter of 2012. Overall, 89.0% of the increase in natural gas sales revenue was attributed to increased sales volumes and 11.0% was attributed to the increase in natural gas prices received. The volume increase is due to the ongoing development of our Bakken properties and the continued development of gas pipeline infrastructure. Although gas from certain wells continues to be flared, we have 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 oil and gas production expense increased by $20.3 million to $37.5 million for the three months ended June 30, 2013, from $17.2 million for the three months ended June 30, 2012. The increase is due to a $9.5 million increase in production taxes, a $6.9 million increase in lease operating expenses (“LOE”), and an $3.9 million increase in gathering, transportation and marketing expenses ("GTM").

The production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue. On a per unit basis, production taxes increased from $7.80 per barrel sold in the second quarter of 2012 to $8.77 per barrel sold in the second quarter of 2013. This increase is the result of the increase in the crude oil and natural gas prices received in the second quarter of 2013 as compared to the second quarter of 2012.

On a per unit basis, LOE increased from $5.60 per barrel sold in the second quarter of 2012 to $6.33 per barrel sold in the second quarter of 2013. The increase is primarily the result of increased well maintenance in the second quarter of 2013, as we incurred approximately $1.2 million, as compared to approximately $237,000 in the second quarter of 2012. In addition, the largest component of our lease operating expense continues to be the disposal of produced water. 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 and continuing into 2013, we 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 related to water disposal to continue to decrease on a per unit basis.

On a per unit basis, GTM increased from $1.49 per barrel sold in the second quarter of 2012 to $2.67 per barrel sold in the second quarter of 2013. This increase is primarily the result of an increased percentage of our total sales volumes being natural gas sales. Natural gas sales volumes as a percentage of total sales volumes increased from 9.7% in the second quarter of 2012 to 13.0% in the second quarter of 2013. Comparatively, the GTM related to natural gas is significantly higher than that of crude oil when measured on a per BOE basis. Consequently, as our natural gas sales volumes on a percentage of total sales volumes increases, we expect our GTM on a per BOE basis to increase.

Depletion, depreciation, amortization and abandonment liability accretion (“DD&A”) expense. Our DD&A increased $28.2 million to $62.4 million for the three months ended June 30, 2013, from $34.2 million for the three months ended June 30, 2012. This increase is due to more volumes being sold in the second quarter of 2013 as sales increased by approximately 956.2 MBOE. On a per unit basis, DD&A decreased from $29.59 per BOE in the second quarter of 2012 to $29.56 per BOE in the second quarter of 2013.

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General and administrative (“G&A”) expense. G&A expense increased by $2.2 million to $10.3 million for the three months ended June 30, 2013, from $8.1 million for the same period in 2012. Total employees have increased to 134 at June 30, 2013, from 100 at June 30, 2012. On a per unit basis, G&A decreased from $7.05 per barrel sold in the second quarter of 2012 to $4.89 per barrel sold in the second quarter of 2013. The decrease is primarily due to our increase in sales volumes from our ongoing Bakken development program.

Our G&A expense includes the non-cash expense for stock‑based compensation for stock options and share grants under our 2007 Stock Incentive Plan. For the three months ended June 30, 2013, this expense was $3.5 million as compared to $2.7 million for the same period in 2012.

Operating income. Our operating income was approximately $63.2 million for the three months ended June 30, 2013, as compared to approximately $26.2 million for the three months ended June 30, 2012. This increase in operating income is attributed to our on-going successful completions of wells and resulting increase in sales volumes in our Bakken play.

Gain on commodity price risk management activities. Primarily due to the decrease in NYMEX crude oil prices at June 30, 2013 as compared to March 31, 2013, we incurred a total gain on our price risk management activities of $22.7 million for the three months ended June 30, 2013 as compared to a gain of $95.6 million for the three months ended June 30, 2012. This gain is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. This gain was comprised of approximately $1.8 million of realized gains for transactions that were settled during the second quarter of 2013 and $20.9 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 June 30, 2013. 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 June 30, 2013, we recognized interest expense of approximately $15.8 million, as compared to $3.5 million for the three months ended June 30, 2012.

We incurred interest expense for the three months ended June 30, 2013 and 2012 of approximately $22.4 million and $15.0 million, respectively, related to the credit facility and our Senior Notes. Included in interest expense for the three months ended June 30, 2013 and 2012 was the amortization of deferred financing costs and bond premium of $827,000 and $617,000, respectively. For the three months ended June 30, 2013 and 2012, we capitalized interest costs of $7.4 million and $12.0 million, respectively.

Income tax expense. 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. For the three months ended June 30, 2013 and 2012, we recognized income tax expense of $26.1 million and $25.9 million, respectively.

Net income. Net income decreased by $48.8 million to $44.3 million for the three months ended June 30, 2013, from $93.1 million for the same period in 2012. This decrease was primarily the result of a $72.9 million decrease in the gain recognized on our commodity price risk management activities for the three months ended June 30, 2013 as compared to the same period in 2012. To a lesser extent, this decrease was impacted by the $12.2 million increase in interest expense for the three months ended June 30, 2013 as compared to the same period in 2012. However, offsetting this decrease was an increase in operating income of $37.0 million for the three months ended June 30, 2013 as compared to the same period in 2012.

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Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Oil sales revenues. Oil sales revenues increased by $160.0 million to $319.2 million for the six months ended June 30, 2013 as compared to oil sales of $159.2 million for the same period in 2012. In the first half of 2013, our crude oil sales averaged 19,637 barrels per day. Our oil sales volume increased 84.9% to 3,554.3 MBbls in the first half of 2013 as compared to 1,922.4 MBbls in the first half of 2012. The volume increase is due to the ongoing development of our Bakken properties. The average price we realized on the sale of our oil increased from $82.81 per barrel sold in the first half of 2012 to $89.81 per barrel sold in the first half of 2013. Overall, 91.6% of the increase in oil sales revenue was attributed to increased volumes and 8.4% was attributed to the increase in crude oil prices received.

Natural gas sales revenues. Natural gas revenues increased by $12.8 million to $19.3 million for the six months ended June 30, 2013 as compared to natural gas revenues of $6.5 million for the same period in 2012. Natural gas sales volumes increased by 1,888.1 MMcf to 3,061.4 MMcf for the six months ended June 30, 2013. In the first half of 2013, our natural gas sales averaged 16.9 MMcf per day. The average price we realized on the sale of our natural gas was $6.31 per Mcf in the first half of 2013 compared to $5.54 per Mcf in the first half of 2012. Overall, 93.0% of the increase in natural gas sales revenue was attributed to increased sales volumes and 7.0% was attributed to the increase in natural gas prices received. The volume increase is due to the ongoing development of our Bakken properties and the continued development of gas pipeline infrastructure. Although gas from certain wells continues to be flared, we have 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 oil and gas production expense increased by $39.0 million to $73.5 million for the six months ended June 30, 2013, from $34.5 million for the six months ended June 30, 2012. The increase is due to a $18.7 million increase in production taxes, a $13.6 million increase in LOE, and a $6.7 million increase in GTM.

The production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue. On a per unit basis, production taxes increased from $8.27 per barrel sold in the first half of 2012 to $8.92 per barrel sold in the first half of 2013. This increase is the result of the increase in the crude oil and natural gas prices received in the first half of 2013 as compared to the first half of 2012.

On a per unit basis, LOE increased from $6.26 per barrel sold in the first half of 2012 to $6.61 per barrel sold in the first half of 2013. The increase is primarily the result of increased well maintenance in the first half of 2013, as we incurred approximately $2.6 million, as compared to approximately $724,000 in the first half of 2012. In addition, the largest component of our lease operating expense continues to be the disposal of produced water. 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 and continuing into 2013, we 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 related to water disposal to continue to decrease on a per unit basis.

On a per unit basis, GTM increased from $1.76 per barrel sold in the first half of 2012 to $2.56 per barrel sold in the first half of 2013. This increase is primarily the result of an increased percentage of our total sales volumes being natural gas sales. Natural gas sales volumes as a percentage of total sales volumes increased from 9.2% in the first half of 2012 to 12.6% in the first half of 2013. Comparatively, the GTM related to natural gas is significantly higher than that of crude oil when measured on a per BOE basis. Consequently, as our natural gas sales volumes on a percentage of total sales volumes increases, we expect our GTM on a per BOE basis to increase.

Depletion, depreciation, amortization and abandonment liability accretion expense. Our DD&A increased $59.3 million to $119.8 million for the six months ended June 30, 2013, from $60.5 million for the six months ended June 30, 2012. This increase is due to more volumes being sold in the first half of 2013 as sales increased by approximately 1,946.6 MBOE. On a per unit basis, DD&A increased from $28.56 per BOE in the first half of 2012 to $29.47 per BOE in the first half of 2013.

General and administrative expense. G&A expense increased by $4.6 million to $20.6 million for the six months ended June 30, 2013, from $16.0 million for the same period in 2012. Total employees have increased to 134 at June 30, 2013, from 100 at June 30, 2012. On a per unit basis, G&A decreased from $7.57 per barrel sold in the first half of 2012 to $5.08 per barrel sold in the first half of 2013. The decrease is primarily due to our increase in sales volumes from our ongoing Bakken development program.

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Our G&A expense includes the non-cash expense for stock‑based compensation for stock options and share grants under our 2007 Stock Incentive Plan. For the six months ended June 30, 2013, this expense was $7.2 million as compared to $5.1 million for the same period in 2012.

Operating income. Our operating income was approximately $124.6 million for the six months ended June 30, 2013, as compared to approximately $54.7 million for the six months ended June 30, 2012. This increase in operating income is attributed to our on-going successful completions of wells and resulting increase in sales volumes in our Bakken play.

Gain on commodity price risk management activities. Primarily due to the decrease in NYMEX crude oil prices at June 30, 2013 as compared to December 31, 2012, we incurred a total gain on our price risk management activities of $6.9 million for the six months ended June 30, 2013 as compared to a gain of $72.2 million for the six months ended June 30, 2012. This gain is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. This gain was comprised of approximately $3.2 million of realized gains for transactions that were settled during the first half of 2013 and $3.7 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 June 30, 2013. 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 six months ended June 30, 2013, we recognized interest expense of approximately $29.6 million, as compared to $8.2 million for the six months ended June 30, 2012.

We incurred interest expense for the six months ended June 30, 2013 and 2012 of approximately $43.8 million and $28.5 millions, respectively, related to the credit facilities and our Senior Notes. Included in interest expense for the six months ended June 30, 2013 and 2012 was the amortization of deferred financing costs and bond premium of $1.7 million and $1.3 million, respectively. Additionally, in the first quarter of 2012, we recognized a $3.0 million prepayment penalty for the early termination of the second lien credit agreement. For the six months ended June 30, 2013 and 2012, we capitalized interest costs of $15.9 million and $24.5 million, respectively.

Income tax expense. 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. For the six months ended June 30, 2013 and 2012, we recognized income tax expense of $38.9 million and $25.9 million, respectively.

Net income. Net income decreased by $31.1 million to $63.7 million for the six months ended June 30, 2013, from $94.8 million for the same period in 2012. This decrease was primarily the result of a $65.3 million decrease in the gain recognized on our commodity price risk management activities for the six months ended June 30, 2013 as compared to the same period in 2012. To a lesser extent, this decrease was impacted by the increases in interest expense and income taxes of $21.4 million and $13.0 million, respectively, for the six months ended June 30, 2013 as compared to the same period in 2012. However, offsetting this decrease was an increase in operating income of $69.9 million for the six months ended June 30, 2013 as compared to the same period in 2012.

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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 June 30, 2013 and December 31, 2012.

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—Basis of Presentation and Significant Accounting Policies to the Company’s consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2012, as well as in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in such Form 10-K. There have been no significant changes in the Company’s application of its critical accounting policies during the first half of 2013.

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 section titled Recent Accounting Pronouncements under Note 2—Basis of Presentation and Significant Accounting Policies under Item 1 of this Quarterly Report.

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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our primary market risk is market changes in oil and natural gas prices. The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. 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. All hedges are accounted for using mark-to-market accounting.

We use costless 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.

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

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. Our wholly‑-owned subsidiary, Kodiak Oil & Gas (USA) Inc., is currently a party to derivative contracts with eight counterparties, and the Company is a guarantor of Kodiak Oil & Gas (USA) Inc. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties 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 June 30, 2013 are summarized below:

Collars	Basis(1)	Quantity (Bbl/d)	Strike Price ($/Bbl)
Jul 1, 2013—Dec 31, 2013	NYMEX	500	$85.00 - $117.00
Jul 1, 2013—Dec 31, 2015	NYMEX	300 - 425	$85.00 - $102.75
Swaps	Basis(1)	Average Quantity (Bbl/d)	Average Swap Price ($/Bbl)
2013 Total	NYMEX	18,105	$95.64
2014 Total	NYMEX	14,800	$91.67
2015 Total	NYMEX	1,625	$87.13

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Subsequent to June 30, 2013, the Company entered into additional commodity derivative contracts as summarized below:

Contract Type	Basis (1)	Quantity  (Bbl/d)	Swap Price ($/Bbl)	Term
Swap	NYMEX	500	$96.63	Jul 1, 2013—Dec 31, 2013
Swap	NYMEX	1,000	$96.78	Jul 1, 2013—Dec 31, 2013
Swap	NYMEX	500	$96.70	Jul 1, 2013—Dec 31, 2013
Swap	NYMEX	500	$91.00	Jan 1, 2014—Dec 31, 2014
Swap	NYMEX	500	$91.00	Jan 1, 2014—Dec 31, 2014

(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 June 30, 2013, we had $800.0 million outstanding under our 2019 Notes due December 1, 2019 at a fixed interest rate of 8.125% as well as $350.0 million outstanding under our 2021 Notes due January 15, 2021 at a fixed interest rate of 5.50%.

In addition, as of June 30, 2013, we had (i) $550 million available to us under our credit facility, of which, $291.0 million was drawn at June 30, 2013. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at June 30, 2013 under our credit facility of $550 million, a 1.0% increase in interest rates would result in additional annualized interest expense of $5.5 million.

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

ITEM 4. CONTROLS AND PROCEDURES

Management, with the participation of our 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 June 30, 2013. 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.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We have no material legal proceedings pending, and we do not know of any material proceedings contemplated by governmental authorities. There are no material proceedings to which any director, officer or any of our affiliates, any owner of record or beneficially of more than five percent of any class of our voting securities, or any associate of any such director, officer, our affiliates, or security holder, is a party adverse to us or our consolidated subsidiary or has a material interest adverse to us or our consolidated subsidiary.

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, 2012, as filed with the SEC on February 28, 2013. The risk factors in our Annual Report on Form 10-K for the year ended December 31, 2012, 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
4.1	Supplemental Indenture, dated as of July 30, 2013, among Kodiak Oil & Gas Corp., Kodiak Williston, LLC, KOG Finance, LLC, U.S. Bank National Association and Computershare Trust Company of Canada, to the Indenture, dated as of November 23, 2011, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc., U.S. Bank National Association and Computershare Trust Company of Canada
4.2	Supplemental Indenture, dated as of July 30, 2013, among Kodiak Oil & Gas Corp., Kodiak Williston, LLC, KOG Finance, LLC, U.S. Bank National Association and Computershare Trust Company of Canada, to the Indenture, dated as of January 15, 2013, among Kodiak Oil & Gas Corp., Kodiak Oil & Gas (USA) Inc., U.S. Bank National Association and Computershare Trust Company of Canada
23.1	Consent of Netherland, Sewell & Associates, Inc.
31.1	Certification of the Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a)
31.2	Certification of the Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a)
32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350
99.1	Reserve Estimate Report of Netherland, Sewell & Associates, Inc.
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 Section 13 or 15(d) 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.
August 1, 2013	By:	/s/ LYNN A. PETERSON
		Lynn A. Peterson
		President and Chief Executive Officer
		(principal executive officer)
August 1, 2013	By:	/s/ JAMES P. HENDERSON
		James P. Henderson
		Chief Financial Officer
		(principal financial and accounting officer)

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