KOG 03.31.2014 10-Q

Quantity (Bbl/d)

Strike Price
($/Bbl)

Apr 1, 2014—Dec 31, 2015

$85.00 - $102.75

(Unaudited)



	March 31, 2014			December 31, 2013
ASSETS
Current Assets:
Cash and cash equivalents	$	15,966		$	90
Accounts receivable
Trade	84,316			108,883
Accrued sales revenues	139,640			121,843
Inventory and prepaid expenses	12,838			11,367
Deferred tax asset, net	19,740			14,300
Total Current Assets	272,500			256,483

Oil and gas properties (full cost method), at cost:
Proved oil and gas properties	3,772,963			3,556,667
Unproved oil and gas properties	572,410			641,644
Equipment and facilities	27,804			27,712
Less-accumulated depletion, depreciation, amortization, and accretion	(694,657		)	(605,700		)
Net oil and gas properties	3,678,520			3,620,323

Commodity price risk management asset	283			1,290
Property and equipment, net of accumulated depreciation of $2,302 at March 31, 2014 and $1,980 at December 31, 2013	4,031			3,928
Deferred financing costs, net of amortization of $24,524 at March 31, 2014 and $22,963 at December 31, 2013	40,186			41,746

Total Assets	$	3,995,520		$	3,923,770

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	274,833		$	272,858
Accrued interest payable	29,975			24,425
Commodity price risk management liability	31,779			20,334
Total Current Liabilities	336,587			317,617

Noncurrent Liabilities:
Credit facility	700,000			708,000
Senior notes, net of accumulated amortization of bond premium of $1,193 at March 31, 2014 and $1,024 at December 31, 2013	1,554,807			1,554,976
Commodity price risk management liability	264			—
Deferred tax liability, net	157,930			133,700
Asset retirement obligations	17,520			16,405
Total Noncurrent Liabilities	2,430,521			2,413,081

Total Liabilities	2,767,108			2,730,698

Stockholders’ Equity:
Common stock—no par value; unlimited authorized
Issued and outstanding: 266,506,464 shares as of March 31, 2014 and 266,249,765 shares as of December 31, 2013	1,030,690			1,024,462
Retained earnings	197,722			168,610
Total Stockholders’ Equity	1,228,412			1,193,072

Total Liabilities and Stockholders’ Equity	$	3,995,520		$	3,923,770



	For the Three Months Ended March 31,
	2014			2013
Revenues:
Oil sales	$	237,249		$	155,843
Gas sales	19,766			9,207
Total revenues	257,015			165,050

Operating expenses:
Oil and gas production	57,037			35,991
Depletion, depreciation, amortization and accretion	89,629			57,385
General and administrative	13,918			10,302
Total operating expenses	160,584			103,678

Operating income	96,431			61,372

Other income (expense):
Loss on commodity price risk management activities, net	(24,805		)	(15,744		)
Interest income (expense), net	(24,550		)	(13,810		)
Other income	826			426
Total other income (expense)	(48,529		)	(29,128		)

Income before income taxes	47,902			32,244

Income tax expense	18,790			12,800

Net income	$	29,112		$	19,444

Earnings per common share:
Basic	$	0.11		$	0.07
Diluted	$	0.11		$	0.07

Weighted average common shares outstanding:
Basic	266,292,773			265,328,392
Diluted	269,935,030			267,969,663



	For the Three Months Ended March 31,
	2014			2013
Cash flows from operating activities:
Net income	$	29,112		$	19,444
Reconciliation of net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	89,629			57,385
Amortization of deferred financing costs and debt premium	1,391			918
Loss on commodity price risk management activities, net	24,805			15,744
Settlements on commodity derivative instruments	(12,089		)	1,438
Stock‑based compensation	5,120			3,724
Deferred income taxes	18,790			12,800
Changes in current assets and liabilities:
Accounts receivable‑trade	24,992			(15,013		)
Accounts receivable‑accrued sales revenues	(17,797		)	(9,439		)
Prepaid expenses and other	(368		)	134
Accounts payable and accrued liabilities	(5,610		)	7,493
Accrued interest payable	5,550			19,945
Net cash provided by operating activities	163,525			114,573

Cash flows from investing activities:
Oil and gas properties	(210,683		)	(275,805		)
Sale of oil and gas properties	70,848			—
Equipment, facilities and other	(497		)	(4,065		)
Net cash used in investing activities	(140,332		)	(279,870		)

Cash flows from financing activities:
Borrowings under credit facility	80,000			163,875
Repayments under credit facility	(88,000		)	(358,875		)
Proceeds from the issuance of senior notes	—			350,000
Proceeds from the issuance of common shares	700			260
Purchase of common shares	(17		)	(518		)
Debt and share issuance costs	—			(6,920		)
Net cash provided by (used in) financing activities	(7,317		)	147,822

Increase (decrease) in cash and cash equivalents	15,876			(17,475		)

Cash and cash equivalents at beginning of the period	90			24,060

Cash and cash equivalents at end of the period	$	15,966		$	6,585

Supplemental cash flow information:
Oil & gas property accrual included in accounts payable and accrued liabilities	$	172,110		$	146,840
Cash paid for interest	$	26,024		$	1,458

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”.

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 2013 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. There have been no material changes to the information disclosed in the notes to the consolidated financial statements included in Kodiak's 2013 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 its 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 its estimates are reasonable.

On July 12, 2013, the Company's wholly owned 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 and the acquired producing properties contributed revenue of $30.2 million to the Company for the three months ended March 31, 2014. Total transaction costs related to the acquisition incurred were approximately $185,000. Transaction costs are recorded in the statement of operations within the general and administrative expense line item. No transaction costs for the July 2013 Acquisition were recorded within the three months ended March 31, 2014 and 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. In December 2013, the Company completed the transaction’s post-closing settlement. Management has not had the opportunity to complete its assessment of the fair values of assets acquired and liabilities assumed. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and is subject to revision as the Company continues to evaluate the fair value of the acquisition (in thousands):



Purchase Price	July 12, 2013
Consideration Given
Cash from credit facility	$	731,785

Total consideration given	$	731,785

Preliminary Allocation of Purchase Price
Proved oil and gas properties	$	416,052
Unproved oil and gas properties	292,518
Total fair value of oil and gas properties acquired	$	708,570

Working capital	$	25,442
Asset retirement obligation	(2,227		)

Fair value of net assets acquired	$	731,785

Working capital acquired was estimated as follows:
Accounts receivable	$	61,271
Accrued liabilities	(35,829		)

Total working capital	$	25,442

The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired in July 2013 for the three months ended March 31, 2013 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 $11.4 million for the three months ended March 31, 2013. The pro forma information includes the effects of adjustments for amortization of financing costs of $204,000 for the three months ended March 31, 2013. The pro forma information includes the effects of the incremental interest expense on acquisition financing of $2.9 million for the three months ended March 31, 2013. The pro forma financial information includes total capitalization of interest expense of $10.2 million for the three months ended March 31, 2013. The pro forma information includes the effects of adjustments for income tax expense of $7.3 million for the three months ended March 31, 2013.

The following 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.



	March 31, 2014		December 31, 2013
Credit Facility due April 2018	$	700,000	$	708,000
2019 Notes due December 2019	800,000		800,000
Unamortized Premium on 2019 Notes	4,807		4,976
2021 Notes due January 2021	350,000		350,000
2022 Notes due February 2022	400,000		400,000
Total Long-Term Debt	$	2,254,807	$	2,262,976
Less: Current Portion of Long Term Debt	—		—
Total Long-Term Debt, Net of Current Portion	$	2,254,807	$	2,262,976

Kodiak Oil & Gas (USA) Inc. (the “Borrower”) has in place a $1.5 billion credit facility with a syndicate of banks, which is subject to a borrowing base. The credit facility matures on April 2, 2018. As of March 31, 2014, the credit facility was subject to a borrowing base of $1.35 billion. 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. In April 2014, the redetermination was completed and the existing borrowing base was affirmed.

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 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. 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 London interbank offered ("LIBO") rate is a sliding scale of 1.50% to 2.50%, depending on borrowing base usage. Additionally, the credit facility provides for 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:

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

The credit facility also contains financial covenants requiring the Borrower to comply with a current ratio of consolidated current assets (including unused borrowing capacity) to consolidated current liabilities of not less than 1.0 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. The Company was in compliance with all financial covenants under the credit facility as of March 31, 2014, and through the filing of this report.

As of March 31, 2014, the Company had $700.0 million in outstanding borrowings under the credit facility and as such, the available credit under the credit facility at that date was $650.0 million. Subsequent to March 31, 2014, the Company made additional borrowings of $15.0 million on the credit facility, bringing the outstanding balance as of the date of this filing under the credit facility to $715.0 million. Any borrowings under the credit facility are collateralized by the Borrower’s oil and gas producing properties, the Borrower’s personal property and the equity interests of the Borrower held by the Company. The Company has entered into crude oil commodity derivative instruments with several counterparties that are also lenders under the credit facility. The Company’s obligations under these derivative instruments are secured by the credit facility.

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%. 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, 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%. The interest on the 2021 Notes is payable on January 15 and July 15 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%. 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 $391.8 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 Kodiak Williston, LLC and KOG Finance, LLC 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 March 31, 2014, 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 principal amounts of the Senior Notes redeemed plus accrued and unpaid interest. The Company must offer to purchase the Senior Notes if it sells assets under certain circumstances.

As of March 31, 2014, the Company had deferred financing costs of $40.2 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 months ended March 31, 2014 and 2013, the Company recorded amortization expense of $1.6 million and $1.1 million, respectively.

For the three months ended March 31, 2014 and 2013, the Company incurred interest expense on long-term debt of $31.6 million and $21.4 million, respectively. Of the total interest incurred, the Company capitalized interest costs of $8.4 million and $8.5 million for the three months ended March 31, 2014 and 2013, respectively. Additionally, for the three months ended March 31, 2014 and 2013, interest expense was reduced for the amortization of the bond premium in the amounts of $169,000 and $157,000, respectively.

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 plus any significant unusual or infrequently occurring items recorded in the interim period. The effective income tax rate for the three months ended March 31, 2014 and 2013 was 39.23% and 38.95%, respectively. The Company's effective income tax rate for the three months ended March 31, 2014 and 2013 differed from the U.S. statutory rate of 35% primarily due to state income taxes, estimated permanent differences and changes in the valuation allowance.

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.

As of March 31, 2014, 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 March 31, 2014, 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, 2009 or Canadian tax examinations by the Canadian Revenue Agency for tax years ended on or before December 31, 2002. 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.

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 and “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 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 nine 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. The Company has not designated any of its derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to its commodity derivative instruments. Net gains and losses on commodity price risk management activities are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity price risk management activities are recorded in the commodity price risk management activities line on the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.

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.



		As of March 31, 2014
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	$	2,115	$	(2,115	)	$	—
Crude oil derivative contract	Noncurrent assets	$	1,447	$	(1,164	)	$	283
Crude oil derivative contract	Current liabilities	$	33,894	$	(2,115	)	$	31,779
Crude oil derivative contract	Noncurrent liabilities	$	1,428	$	(1,164	)	$	264



		As of December 31, 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	$	7,278	$	(7,278	)	$	—
Crude oil derivative contract	Noncurrent assets	$	2,731	$	(1,441	)	$	1,290
Crude oil derivative contract	Current liabilities	$	27,612	$	(7,278	)	$	20,334
Crude oil derivative contract	Noncurrent liabilities	$	1,441	$	(1,441	)	$	—

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.

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:

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 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 Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At March 31, 2014 and December 31, 2013, 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.

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, 2021 Notes and the 2022 Notes was derived from available market data. As such, the Company has classified these Senior Notes as Level 2. This disclosure (in thousands) does not impact the Company's financial position, results of operations or cash flows.

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, 2014, the maximum number of shares issuable under the Plan, including those previously issued thereunder, was approximately 37.3 million shares.

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 Three Months Ended March 31, 2014			For the Year Ended December 31, 2013
Risk free rates	1.65 - 2.03%			0.88-2.14%
Dividend yield	—		%	—		%
Expected volatility	79.29 - 79.99%			80.04 - 85.08%
Weighted average expected stock option life	5.55 years			5.81 years

The weighted average fair value at the date of grant for stock options granted is as follows:

Weighted average fair value per share	$	7.24		$	6.80
Total options granted	1,137,100			1,850,900
Total weighted average fair value of options granted	$	8,232,604		$	12,586,120



	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-$2.00	638,448	1.1	$	1.00	638,448	1.1	$	1.00
$2.01-$4.00	1,641,207	3.8	$	3.04	1,641,207	3.8	$	3.04
$4.01-$6.00	314,000	7.0	$	5.06	229,000	6.9	$	5.01
$6.01-$8.00	862,000	7.0	$	6.78	621,000	6.5	$	6.63
$8.01-$10.00	1,753,700	8.4	$	9.15	1,051,200	8.3	$	9.34
$10.01-$12.00	1,403,000	9.7	$	10.71	7,666	8.0	$	10.15
$12.01-$13.31	203,000	9.6	$	12.74	—	0.0	$	0.00
	6,815,355	6.7	$	6.86	4,188,521	5.1	$	4.96

The aggregate intrinsic value of vested and exercisable options as of March 31, 2014 was $30.1 million. The aggregate intrinsic value of options vested and expected to vest as of March 31, 2014 was $35.6 million. The intrinsic value is based on the Company’s March 31, 2014 closing common stock price of $12.14. 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 three months ended March 31, 2014 was $4.7 million.

As of March 31, 2014, there were 1.3 million awarded and unvested performance based RSUs, 1.2 million RSU's that may be awarded subject to performance based metrics and 108,500 unvested restricted stock with a combined weighted average grant date fair value of $10.19 per share. The total fair value vested during the three months ended March 31, 2014 was $153,675. A summary of the restricted stock and RSUs outstanding is as follows:

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 and Restricted Stock Units" for additional discussion.



	For the Three Months Ended March 31,
	2014			2013
Basic net income	$	29,112		$	19,444
Income allocable to participating securities	(8		)	(3		)
Diluted net income	$	29,104		$	19,441

Basic weighted average common shares outstanding	266,292,773			265,328,392
Effect of dilutive securities
Options to purchase common shares	6,555,855			4,160,693
Assumed treasury shares purchased	(3,783,671		)	(2,099,034		)
Unvested restricted stock units	870,073			579,612
Diluted weighted average common shares outstanding	269,935,030			267,969,663

Basic net income per share	$	0.11		$	0.07
Diluted net income per share	$	0.11		$	0.07

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 January 31, 2017 and December 31, 2014, respectively. Total rental commitments under non-cancelable leases for office space were $3.5 million at March 31, 2014. The future minimum lease payments under these non-cancelable leases are as follows: $1.0 million in 2014, $1.3 million in 2015, $1.2 million in 2016, $0 in 2017, and $0 in 2018.

As of March 31, 2014, the Company had issued $800.0 million of 2019 Notes, $350.0 million of 2021 Notes, and $400.0 million of 2022 Notes, all of which are guaranteed on a senior unsecured basis by the Company's wholly-owned subsidiaries, Kodiak Oil & Gas (USA) Inc, Kodiak Williston, LLC and KOG Finance, LLC. Kodiak Oil & Gas Corp, as the parent company, has no independent assets or operations. 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, as of the most recent fiscal year end, other than as described above, the parent Company’s wholly‑owned subsidiary does not have restricted assets that exceed 25% of consolidated net assets that may not be transferred to the Company in the form of loans, advances, or cash dividends by the subsidiaries 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.

The Company is subject to litigation and claims in pending or threatened legal proceedings arising in the normal course of its business, including, but not limited to, royalty claims and contract claims. The Company believes all such matters are without merit or involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition, results of operations or cash flows.

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, 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 and under Item 1A "Risk Factors" of this quarterly report on Form 10-Q. 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.

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 within a high-potential resource play. We intend to continue to expand our asset base by drilling and completing wells within 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 March 31, 2014, we owned an interest in approximately 323,000 gross (171,000 net) acres in the Williston Basin and have an interest in 629 gross (250.5 net) producing wells in the Williston Basin.

We expect to continue to operate seven drilling rigs and utilize one to two completion crews as needed throughout 2014. Overall, we anticipate that our drilling and well completion efforts will remain on pace with our previously announced 2014 well count of approximately 100 net wells for the year. We will monitor our progress throughout the year and adjust our plans accordingly, based on crude oil pricing and service costs. We have a staggered rig termination schedule with multiple rigs terminating in 2014, allowing us to adjust our rig count to align with our cash flow and capital expenditure projections. The contracts for these rigs may be extended or operated on a well to well basis.

Our operations in the first quarter of 2014 were impacted by extreme winter weather conditions, with exceptionally cold temperatures. This resulted in a reduction in the number of net operated wells that we completed as compared to our expectations. In addition, we experienced reduced activity on non-operated properties and we divested certain producing properties during the first quarter of 2014. All of these factors contributed to lower than anticipated sales volumes for the first quarter of 2014. Based upon information provided by operators of some of our non-operated properties, we anticipate that the activity level on our non-operated properties will be less in 2014 than in previous years.

We continue to test downspacing in an effort to determine the optimum well bore density. In 2013, we completed twelve wells within a 1,280-acre drilling spacing units ("DSU"), with six wells in the Middle Bakken and six wells in the Three Forks. In December 2013, we completed the first four-well pad where well bore spacing was tightened to approximately 660 feet within the Middle Bakken and Three Forks as compared to 800 feet on our 2013 twelve-well pilot program. Ultimately, as part of our 2014 pilot program, within a 1,280-acre DSU, we plan to complete eight wells in the Middle Bakken and eight wells in the Three Forks, including two wells in the lower bench of the Three Forks. While early production numbers appear encouraging with respect to the tighter well bore spacing, we are still in the early stages of this work and we have not conclusively determined the long term impact on estimated ultimate recoveries.



			Three Months Ended
	Annual		March 31, 2014
	2014 Budget		Actual
Capital Expenditures
Drilling and completion costs	$	890.0	$	204.9
Infrastructure and leasehold acquisitions	50.0		3.7
Total capital expenditures	$	940.0	$	208.6

Divestitures
Proved and unproved oil and gas properties			$	(70.8	)

Non-Cash Capitalized Costs
Asset retirement obligations			$	0.9
Capitalized interest			8.4

Total capitalized costs, net of divestitures			$	147.1

During the three months ended March 31, 2014, we incurred capital expenditures of $208.6 million related to our oil field operations to complete 19.0 net wells. Our average well costs continue to decline in the Williston Basin. Our operated completed well costs averaged approximately $9.3 million in the first quarter of 2014 and continue to trend downward with current cost estimates below $9.0 million. The declining well costs result from a combination of field efficiency gains and the reduction of third party oil field service costs.

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 an annual basis since we began our operations in the Bakken play in 2009. This increase is directly related to our proven ability to develop our properties and acquisitions. 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.

As of the date of this filing, we have $715.0 million outstanding under this credit facility, with available borrowings of $635.0 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 please refer to Note 4 - Long-Term Debt under Item 1 in this Quarterly Report.

We are dependent on our anticipated cash flows from operations and, to a lesser extent, the expected borrowing availability under our credit facility to fund our remaining 2014 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. We operate the majority of our leasehold; therefore, we have the ability to adjust our drilling schedule to reflect a change in commodity prices or oilfield service environment. At this time the majority of our leasehold is held by production.

The measure of working capital is less meaningful to understanding our financial position because of the availability of our borrowing base which (as described above in "Credit facility") was $1.35 billion at March 31, 2014, of which $650.0 million was available to us. 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. Additionally, since our principal source of operating cash flows (proved reserves to be produced in future years) is not considered working capital, we often have negative working capital. Our working capital was a deficit of $64.1 million at March 31, 2014, as compared to a deficit of $61.1 million at December 31, 2013.

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

We 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.

Net cash provided by operating activities. The key component of our net cash provided by operating activities is the revenue derived from our crude oil sales and the crude oil prices received for those sales. For the three months ended March 31, 2014 as compared to the three months ended March 31, 2013, our net cash provided by operating activities increased by $49.0 million, primarily due to the increase in crude oil sales volumes of approximately 1.0 million barrels. 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. As such, 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. For the three months ended March 31, 2014 as compared to the three months ended March 31, 2013, our net cash used in investing activities decreased by $139.5 million. This decrease was primarily attributed to the proceeds from divestitures of oil and gas properties in the amounts of $70.8 million in the first quarter of 2014. Additionally, for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013 our capital expenditures decreased by $65.1 million related to drilling and completions activities. This decrease is primarily due to ongoing cost reduction on a per well basis.

Net cash provided by (used in) financing activities. For the three months ended March 31, 2014 as compared to the three months ended March 31, 2013, our net cash provided by financing activities decreased by $155.1 million. This decrease was primarily the result of the $343.1 million in net proceeds received from our 2021 Notes offering during the first quarter of 2013. Additionally, for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013, our net repayments under our credit facility decreased by $187.0 million. All of the net proceeds from the 2021 Notes issued in the first quarter of 2013 were used to repay borrowings on our credit facility.

Our Williston Basin acreage is located primarily in Mountrail, Dunn, McKenzie and Williams counties of North Dakota. Our primary geologic target is the Bakken Pool where our primary objective is the Middle Bakken, a dolomitic, sandy interval between the two Bakken Shales at an approximate vertical depth of 10,300-11,300 feet, and the Three Forks that is present 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.

The majority of 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 estimated ultimate recoveries (“EURs”) that range from 450 MBOE to over 1,000 MBOE.

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; (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:

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, 2013, this field contained 99.9% of our total proved reserves. Our revenues are directly affected by oil and natural gas 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 for the periods indicated:



	For the Three Months Ended March 31,
	2014			2013
Sales Price:
Oil ($/Bbls)	$	88.62		$	90.80
Gas ($/Mcf) ₍₁₎	$	8.56		$	6.48
BOE ($/BOE)	$	83.93		$	84.51

Commodity Price Risk Management Activities ($/Sales BOE):
Settlements on commodity price risk management activities	$	(3.95	)	$	0.74

Production Costs ($/Sales BOE):
Lease operating expenses	$	7.43		$	6.90
Production taxes	$	8.95		$	9.08
Gathering, transportation, marketing	$	2.25		$	2.45
DD&A	$	29.27		$	29.38
G&A	$	4.54		$	5.28
Stock‑based compensation	$	1.67		$	1.91

Oil sales revenues. Oil sales revenues increased by $81.4 million to $237.2 million for the three months ended March 31, 2014 as compared to oil sales of $155.8 million for the same period in 2013. Our oil sales volume increased 56% to 2,677 thousand barrels (“MBbls”) in the first quarter of 2014 as compared to 1,716 MBbls in the first quarter of 2013. In the first quarter of 2014, our crude oil sales averaged 29.7 MBbls per day. The volume increase is due to the development of our Bakken properties as well as our acquisition in July 2013. Of the 961 MBbls increase in oil sales volume, 331 MBbls is related to the increase in production from producing wells acquired in the July 2013 acquisition and 630 MBbls is attributed to our ongoing development of our properties and undeveloped acreage prior to this acquisition. The average price we realized on the sale of our oil decreased from $90.80 per barrel sold in the first quarter of 2013 to $88.62 per barrel sold in the first quarter of 2014. Overall, 104.6% of the increase in oil sales revenue was attributed to increased volumes and negative 4.6% was attributed to the decrease in crude oil prices received.

Natural gas sales revenues. Natural gas revenues increased by $10.6 million to $19.8 million for the three months ended March 31, 2014 as compared to natural gas revenues of $9.2 million for the same period in 2013. Natural gas sales volumes increased by 63% to 2,310 million cubic feet ("MMcf") for the three months ended March 31, 2014 as compared to 1,420 MMcf in the first quarter of 2013. In the first quarter of 2014, our natural gas sales averaged 25.7 MMcf per day. The average price we realized on the sale of our natural gas was $8.56 per Mcf in the first quarter of 2014 compared to $6.48 per Mcf in the first quarter of 2013. Overall, 72.1% of the increase in natural gas sales revenue was attributed to increased sales volumes and 27.9% was attributed to the increase in natural gas prices received. The volume increase is due to the development of our Bakken properties as well as our acquisition in July 2013. Of the 890 MMcf increase in natural gas sales volume, 106 MMcf is related to the increase in production from producing wells acquired in the July 2013 acquisition and 784 MMcf is attributed to our ongoing development of our properties and undeveloped acreage prior to this acquisition. 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 $21.0 million to $57.0 million for the three months ended March 31, 2014, from $36.0 million for the three months ended March 31, 2013. The increase is due to a $9.7 million increase in production taxes, a $9.3 million increase in lease operating expenses (“LOE”), and a $2.1 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 decreased from $9.08 per barrel sold in the first quarter of 2013 to $8.95 per barrel sold in the first quarter of 2014. This decrease is the result of the decrease in the crude oil and natural gas prices received in the first quarter of 2014 as compared to the first quarter of 2013. Production taxes as a percentage of sales revenue was 10.7% for the three months ended March 31, 2014 as compared to 10.7% for the first quarter of 2013.

On a per unit basis, GTM decreased from $2.45 per barrel sold in the first quarter of 2013 to $2.25 per barrel sold in the first quarter of 2014. GTM on a per BOE basis will vary depending on the transportation used and the rates charged by the carrier and natural gas sales volumes as a percentage of total sales volumes. In the first quarter of 2014, a higher percentage of our oil sales were in areas where GTM costs are lower as compared to the first quarter of 2013.

Depletion, depreciation, amortization and abandonment liability accretion (“DD&A”) expense. Our DD&A increased $32.2 million to $89.6 million for the three months ended March 31, 2014, from $57.4 million for the three months ended March 31, 2013. This increase is due to more production volumes being sold in the first quarter of 2014 as sales increased by approximately 1,109 MBOE. On a per unit basis, DD&A decreased from $29.38 per BOE in the first quarter of 2013 to $29.27 per BOE in the first quarter of 2014.

General and administrative (“G&A”) expense. G&A expense increased by $3.6 million to $13.9 million for the three months ended March 31, 2014, from $10.3 million for the same period in 2013. Total employees have increased to 214 at March 31, 2014, from 116 at March 31, 2013. On a per unit basis, G&A decreased from $5.28 per barrel sold in the first quarter of 2013 to $4.54 per barrel sold in the first quarter of 2014. The decrease is primarily due to our increase in sales volumes from our ongoing Bakken development program.

Loss on commodity price risk management activities. Primarily due to the increase in NYMEX crude oil futures prices at March 31, 2014 as compared to December 31, 2013, we incurred a net loss on our price risk management activities of $24.8 million for the three months ended March 31, 2014 as compared to a net loss of $15.7 million for the three months ended March 31, 2013. This loss is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. Included in the net loss on our commodity price risk management activities were cash settlements we incurred on our commodity derivative instruments of approximately $12.1 million for transactions that were settled during the first quarter of 2014. The fair value of the open commodity derivative instruments 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.

We incurred interest expense for the three months ended March 31, 2014 and 2013 of approximately $31.6 million and $21.4 million, respectively, related to the credit facilities and our Senior Notes. Included in interest expense for the three months ended March 31, 2014 and 2013 was the amortization of deferred financing costs and bond premium of $1.4 million and $918,000, respectively. For the three months ended March 31, 2014 and 2013, we capitalized interest costs of $8.4 million and $8.5 million, respectively.

Income tax expense. For the three months ended March 31, 2014, we recognized income tax expense of approximately $18.8 million as compared to $12.8 million for the three months ended March 31, 2013. The effective income tax rate for the three months ended March 31, 2014 was 39.23% as compared to 38.95% for the same period in 2013. The effective income tax rate differed for the three months ended March 31, 2014 and 2013 primarily due to state income taxes, estimated permanent differences and changes in the valuation allowance.

Net income. Our net income was approximately $29.1 million for the three months ended March 31, 2014 as compared to $19.4 million for the three months ended March 31, 2013. This increase of $9.7 million was primarily the result of an increase in operating income of $35.1 million for three months ended March 31, 2014 as compared to the same period in 2013. However, net income was negatively impacted by increases in interest expense, net loss recognized on our commodity price risk management activities and income tax expense of $10.7 million, $9.1 million and $6.0 million, respectively, for the three months ended March 31, 2014 as compared to the same period in 2013.

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, 2013, as well as in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in such Form 10-K. There have been no significant changes in the Company’s application of its critical accounting policies during the first three months of 2014.

The demand for most oilfield products and services has increased in the Williston Basin beginning in 2010 and continuing through 2014. 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.

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 commodity derivative instruments are accounted for using mark-to-market accounting.

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

We use swaps to fix the sales price for our anticipated future oil production. Upon settlement, we receive a fixed price for the underlying 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 nine counterparties, and the Company is a guarantor of Kodiak Oil & Gas (USA) Inc. We have 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 our 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 our ability to benefit from favorable price movements. We 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 our existing positions.

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 our own credit rating. We also perform an internal valuation to ensure the reasonableness of third‑party quotes. In consideration of counterparty credit risk, we assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, we consider 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.

In addition, as of March 31, 2014, we had (i) $1.35 billion available to us under our credit facility, of which, $700.0 million was drawn at March 31, 2014. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at March 31, 2014 under our credit facility of $1.35 billion, a 1.0% increase in interest rates would result in additional annualized interest expense of $13.5 million.

Management, with the participation of our President, Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of March 31, 2014. 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.

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.

There have been no material changes, other than the following item, to the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the SEC on February 27, 2014. The risk factors in our Annual Report on Form 10-K for the year ended December 31, 2013, 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.

As a crude oil and natural gas producer, we face various security threats, including security threats to our remote well locations and cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable. Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, corruption of data and financial losses. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to interruptions of production or distribution, damage to our wells and other equipment or property, losses of sensitive information, or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.



Exhibit Number		Description
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

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.



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

1625 Broadway, Suite 250
Denver, Colorado 80202	(303) 592-8075
(Address of principal executive offices)	(Registrant’s telephone number, including area code)



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



PART I - FINANCIAL INFORMATION	3
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)	3
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	27
ITEM 4. CONTROLS AND PROCEDURES	29

PART II - OTHER INFORMATION	29
ITEM 1. LEGAL PROCEEDINGS	29
ITEM 1A. RISK FACTORS	29
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	30
ITEM 3. DEFAULTS UPON SENIOR SECURITIES	30
ITEM 4. MINE SAFETY DISCLOSURES	30
ITEM 5. OTHER INFORMATION	30
ITEM 6. EXHIBITS	31
SIGNATURES	32



	For the Three Months Ended March 31, 2013
Operating revenues	$	207,529
Net income	$	30,964

Earnings per common share
Basic	$	0.12
Diluted	$	0.12



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	%



Swaps	Basis ₍₁₎	Average Quantity (Bbl/d)	Average Swap Price ($/Bbl)
2014 Total	NYMEX	25,800	$93.41
2015 Total	NYMEX	3,625	$88.75


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



	For the Three Months Ended March 31, 2014			For the Year Ended December 31, 2013
Balance beginning of period	$	16,405		$	9,064
Liabilities incurred or acquired	1,412			7,181
Liabilities settled	(647		)	(890		)
Revisions in estimated cash flows	—			—
Accretion expense	350			1,050
Balance end of period	$	17,520		$	16,405


•	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.



	Fair Value Measurements at March 31, 2014 Using
	Level 1		Level 2		Level 3		Total
Financial Assets:
Commodity price risk management asset	$	—	$	283	$	—	$	283

Financial Liabilities:
Commodity price risk management liability	$	—	$	32,043	$	—	$	32,043



	At March 31, 2014				At December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Credit facility	$	700,000	$	700,000	$	708,000	$	708,000
2019 Notes	$	804,807	$	888,000	$	804,976	$	888,000
2021 Notes	$	350,000	$	360,500	$	350,000	$	350,438
2022 Notes	$	400,000	$	410,000	$	400,000	$	398,000



	Number of Options		Weighted Average Exercise Price
Balance outstanding at January 1, 2014	6,100,155		$	6.12

Granted	1,137,100		$	10.78
Canceled	(165,201	)	$	9.81
Exercised	(256,699	)	$	4.82
Balance outstanding at March 31, 2014	6,815,355		$	6.86

Options exercisable at March 31, 2014	4,188,521		$	4.96



	Undeveloped Acreage ₍₁₎		Developed Acreage ₍₂₎		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Williston Basin
North Dakota	115,409	58,069	207,361	113,105	322,770	171,174
Green River Basin
Wyoming	14,589	4,009	9,009	1,799	23,598	5,808
Colorado	5,445	3,067	1,252	1,252	6,697	4,319

Acreage Totals	135,443	65,145	217,622	116,156	353,065	181,301



	Number of Shares		Weighted Average Grant Date Fair Value
Non-vested restricted stock and RSU's at January 1, 2014	2,613,175		$	10.18

Granted	—		—
Forfeited	—		—
Vested	(16,500	)	9.31

Non-vested restricted stock and RSU's at March 31, 2014	2,596,675		$	10.19



	For the Three Months Ended March 31, 2014
	Spud		Completed
	Gross	Net	Gross	Net
Operated wells	25	19.0	20	15.2
Non-operated wells	27	3.1	26	3.8
	52	22.1	46	19.0



	For the Three Months Ended March 31,						Period to period change
	2014			2013			Period to period change

Net cash provided by operating activities	$	163,525		$	114,573		$	48,952
Net cash used in investing activities	(140,332		)	(279,870		)	139,538
Net cash provided by (used in) financing activities	(7,317		)	147,822			(155,139		)
Increase (decrease) in cash and cash equivalents	$	15,876		$	(17,475	)	$	33,351


(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.



	Expiring Acreage
Year Ending	Gross	Net
December 31, 2014	5,838	3,122
December 31, 2015	8,004	6,455
December 31, 2016	3,020	2,130
December 31, 2017	4,612	4,377
Total	21,474	16,084


(1)	We convert Mcf of gas equivalent to oil at a ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.


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



	KODIAK OIL & GAS CORP.

May 1, 2014	By:	/s/ LYNN A. PETERSON
		Lynn A. Peterson
		President and Chief Executive Officer
		(principal executive officer)

May 1, 2014	By:	/s/ JAMES P. HENDERSON
		James P. Henderson
		Chief Financial Officer, Secretary and Treasurer
		(principal financial and accounting officer)