Exhibit 99.3

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)

(Unaudited)

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

3

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 Regulations 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.

Use of Estimates in the Preparation of Financial Statements

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.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-09, which establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method, and the standard will be effective for us in the first quarter of our fiscal year 2018; early adoption is not permitted. We are currently evaluating the impact of this new standard on our consolidated financial statements, as well as which transition method we intend to use.

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.

4

Note 3—Acquisitions and Divestitures

July 2013 Acquisition

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 $32.8 million and $63.0 million to the Company for the three and six months ended June 30, 2014, respectively. Total transaction costs related to the acquisition incurred were approximately $235,000. Transaction costs are recorded in the statement of operations within the general and administrative expense line item.

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. The following table summarizes the purchase price and final allocation of the fair value of assets acquired and liabilities assumed (in thousands):

5

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 three and six months ended June 30, 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 $11.8 million and $23.2 million for the three and six months ended June 30, 2013, 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. The pro forma information includes the effects of the incremental interest expense on acquisition financing of $2.4 million and $5.3 million for the three and six months ended June 30, 2013, respectively. The pro forma financial information includes total capitalization of interest expense of $9.6 million and $19.8 million for the three and six months ended June 30, 2013, respectively. The pro forma information includes the effects of adjustments for income tax expense of $5.8 million and $13.1 million for the three and six months ended June 30, 2013, respectively.

The following pro forma results (in thousands, except share data) 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.

Divestitures

In the six months ended June 30, 2014, the Company divested approximately 20,900 net acres in the Williston Basin for cash proceeds of $70.8 million.

Note 4—Long-Term Debt

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

Credit Facility

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 June 30, 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.

6

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:

Borrowing Base Utilization Grid

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 June 30, 2014, and through the filing of this report.

As of June 30, 2014, the Company had $775.0 million in outstanding borrowings under the credit facility and as such, the available credit under the credit facility at that date was $575.0 million. Subsequent to June 30, 2014, the Company made additional borrowings of $45.0 million on the credit facility, bringing the outstanding balance as of the date of this filing under the credit facility to $820.0 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.

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%. 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.

7

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, 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 June 30, 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 must offer to purchase the Senior Notes at a price equal to 101% of the principal amount of the Senior Notes purchased 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.

Deferred Financing Costs

As of June 30, 2014, the Company had deferred financing costs of $38.6 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, 2014, the Company recorded amortization expense of $1.6 million and $3.1 million, respectively, as compared to $1.0 million and $2.1 million for the three and six months ended June 30, 2013, respectively.

Interest Incurred On Long-Term Debt

For the three and six months ended June 30, 2014, the Company incurred interest expense on long-term debt of $31.8 million and $63.4 million, respectively, as compared to $22.4 million and $43.8 million for the three and six months ended June 30, 2013, respectively. Of the total interest incurred, the Company capitalized interest costs of $7.6 million and $16.0 million for the three and six months ended June 30, 2014, respectively, as compared to $7.4 million and $15.9 million for the three and six months ended June 30, 2013, respectively. Additionally, for the three and six months ended June 30, 2014 interest expense was reduced for the amortization of the bond premium in the amounts of $172,000 and $341,000, respectively, as compared to $160,000 and $317,000 for the three and six months ended June 30, 2013, respectively.

8

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 plus any significant unusual or infrequently occurring items recorded in the interim period. The effective income tax rate for the six months ended June 30, 2014 and 2013 was 38.1% and 37.9%, respectively. The Company’s effective income tax rate for the six months ended June 30, 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.

The Company recognized income tax expense of $12.2 million and $31.0 million for the three and six months ended June 30, 2014, respectively, as compared to $26.1 million and $38.9 million for the three and six months ended June 30, 2013, respectively.

Accounting for Uncertainty in Income Taxes

As of June 30, 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 June 30, 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.

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 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 eleven 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.

9

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.

The Company’s commodity derivative contracts as of June 30, 2014 are summarized below:

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 presentation in the consolidated balance sheet (in thousands):

The Company recognized a net loss on commodity price risk management activities of $56.3 million and $81.1 million for the three and six months ended June 30, 2014, respectively, as compared to a net gain on commodity price risk management activities of $22.7 million and $6.9 million for the three and six months ended June 30, 2013, respectively.

10

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.

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:

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no significant assets or liabilities that were measured at fair value on a non-recurring basis in periods after initial recognition.

The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 7 — Asset Retirement Obligations, and the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 3 — Acquisitions and Divestitures.

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.

11

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, 2014 by level within the fair value hierarchy (in thousands):

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, 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.

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, 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.

12

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, 2014, the maximum number of shares issuable under the Plan, including those previously issued thereunder, was approximately 37.3 million shares. Additionally, as a result of the Arrangement Agreement (please refer to Note 12 — Whiting Petroleum Corporation Arrangement Agreement for further details) the Company plans to vest stock options scheduled to vest on or before January 15, 2015 prior to the closing of the Arrangement. All unvested restricted stock and restricted stock units will vest upon the closing of the Arrangement.

Stock Options

Total compensation expense related to the stock options of $2.4 million and $4.7 million was recognized for the three and six months ended June 30, 2014, respectively, as compared to $1.7 million and $3.7 million recognized for the three and six months ended June 30, 2013, respectively. As of June 30, 2014, there was $10.2 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:

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

13

A summary of the stock options outstanding is as follows:

The following table summarizes information about stock options outstanding at June 30, 2014:

The aggregate intrinsic value of vested and exercisable options as of June 30, 2014 was $31.2 million. The aggregate intrinsic value of options vested and expected to vest as of June 30, 2014 was $40.5 million. The intrinsic value is based on the Company’s June 30, 2014 closing common stock price of $14.55. 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, 2014 was $6.1 million.

Restricted Stock and Restricted Stock Units

Total compensation expense related to restricted stock and restricted stock units (“RSUs”) of $2.8 million and $5.6 million was recognized for the three and six months ended June 30, 2014, respectively, as compared to $1.8 million and $3.5 million was recognized for the three and six months ended June 30, 2013, respectively. As of June 30, 2014, there was $14.2 million of total unrecognized compensation cost related to the restricted stock and the RSUs, which is expected to be amortized over a weighted average period of 2.0 years.

As of June 30, 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 93,500 unvested restricted stock with a combined weighted average grant date fair value of $10.19 per share. The total fair value vested during the six months ended June 30, 2014 was $154,000. A summary of the restricted stock and RSUs outstanding is as follows:

14

15

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 and Restricted Stock Units” 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, 2014 and 2013 (in thousands, except per share data):

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:

16

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 January 31, 2017 and December 31, 2014, respectively. Total rental commitments under non-cancelable leases for office space were $3.2 million at June 30, 2014. The future minimum lease payments under these non-cancelable leases are as follows: $700,000 in 2014, $1.3 million in 2015, $1.2 million in 2016, $0 in 2017, and $0 in 2018.

Drilling Rigs

As of June 30, 2014, the Company was subject to commitments on its drilling rigs. In the event of early termination under all of the contracts, the Company would be obligated to pay an aggregate amount of approximately $53.5 million as of June 30, 2014 as required under the varying terms of the contracts.

Guarantees of the Senior Notes

As of June 30, 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.

Other

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.

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.

17

Note 12—Whiting Petroleum Corporation Arrangement Agreement

On July 13, 2014, the Company entered into an Arrangement Agreement (the “Arrangement Agreement”), among the Company, Whiting Petroleum Corporation, a company organized under the laws of Delaware (“Whiting”) and 1007695 B.C. Ltd., a company organized under the laws of British Columbia, Canada and a wholly-owned subsidiary of Whiting (“Acquiror Canadian Sub”), pursuant to which Acquiror Canadian Sub will acquire all of the outstanding common shares, without par value per share, of the Company (the “Kodiak Common Shares”) and Acquiror Canadian Sub and the Company will amalgamate to form one corporate entity with the Company surviving the amalgamation as part of a plan of arrangement (the “Arrangement”).

Subject to the terms and conditions of the Arrangement Agreement, at the effective time of the Arrangement, each outstanding Kodiak Common Share, other than Kodiak Common Shares with respect to which dissent rights have been properly exercised and not withdrawn (the “Dissenting Shares”), will be exchanged for 0.177 of a share (the “Share Exchange Ratio”) of Whiting common stock, $0.001 par value per share (the “Whiting Common Stock”). Each outstanding stock option to purchase Kodiak Common Shares, restricted stock unit measured in relation to, or settleable in, Kodiak Common Shares and each award of restricted stock relating to Kodiak Common Shares, whether vested or unvested, will be assumed by Whiting and converted automatically at the effective time of the Arrangement into an option, restricted stock unit or restricted stock award, as the case may be, denominated in shares of Whiting Common Stock based on the Share Exchange Ratio and subject to terms and conditions substantially identical to those in effect at the effective time of the Arrangement.

The closing of the Arrangement is subject to satisfaction of certain conditions, including, among others: (i) approval of the Company’s and Whiting’s shareholders; (ii) approval by the Supreme Court of British Columbia (the “Applicable Court”); (iii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”); (iv) the accuracy of representations and warranties of, and compliance with covenants by, the other party; and (v) no more than 5% of the shares of Kodiak Common Shares being Dissenting Shares. The closing of the Arrangement is expected to be completed in the fourth quarter of 2014.

The Company and Whiting have made customary representations, warranties and covenants in the Arrangement Agreement, including, among other things, covenants (i) with respect to the conduct of their respective businesses during the interim period between the execution of the Arrangement Agreement and consummation of the Arrangement and (ii) prohibiting each of the Company and Whiting from soliciting alternative acquisition proposals and providing information to or engaging in discussions with third-parties, except in the limited circumstances as provided in the Arrangement Agreement.

The Arrangement Agreement contains certain termination rights for both the Company and Whiting including, but not limited to, in the event that (i) the Arrangement has not been consummated on or prior to the date that is 180 days after the date of the Arrangement Agreement (subject to an automatic extension of up to 60 additional days to satisfy the conditions related to the expiration or termination of the waiting period under the HSR Act); (ii) the other party materially breaches its representations or covenants and such breach is not, or is not capable of being, cured within 30 days of notice; (iii) the Applicable Court fails to approve the Arrangement, (iv) the Company’s or Whiting’s shareholders fail to approve the Arrangement; or (v) the other party’s board of directors makes an Adverse Recommendation Change (as defined in the Arrangement Agreement), or fails to reaffirm its recommendation following receipt of an acquisition proposal. In addition, prior to obtaining shareholder approval of the Arrangement and subject to the payment of a termination fee, the Company and Whiting each may terminate the Arrangement Agreement in order to enter into an agreement for a Superior Proposal (as defined in the Arrangement Agreement). Upon termination of the Arrangement Agreement, under specified circumstances (including in connection with an Adverse Recommendation Change or a Superior Proposal), either the Company or Whiting will be obligated to pay to the other party a termination fee of $130.0 million and reimburse up to $10.0 million of the other party’s expenses. If the Arrangement Agreement is terminated because a party’s shareholders do not approve the transaction, such party will be obligated to reimburse up to $10.0 million of the other party’s expenses. The Company will incur transaction costs in order to complete the Arrangement Agreement, which may be substantial.

Whiting will take all necessary corporate action to appoint Lynn A. Peterson, the President and Chief Executive Officer and a director of the Company, and James E. Catlin, the Executive Vice President of Business Development and a director of the Company, to the Board of Directors of Whiting as of the effective time of the Arrangement.

18

Subsequent to the announcement of the Arrangement, four putative shareholder direct and derivative class actions were filed in the United States District Court for the District of Colorado alleging breaches of fiduciary duties by the individual members of the Company’s Board of Directors. Those cases are captioned as: (i) Quigley et al. v. Whiting Petroleum Corporation et al., No. 1:14-cv-02023-BNB, filed on July 22, 2014; (ii) Fioravanti et al. v. Krysiak et al., No. 1:14-cv-02037 filed on July 23, 2014; (iii) Wilkinson v. Whiting Petroleum Corporation et al., No. 1:14cv2074 filed on July 25, 2014; and (iv) Goldsmith v. Krysiak et al., No. 1:14cv2098 filed on July 29, 2014. These lawsuits complain about the price offered in the Arrangement and the process followed by the Company’s Board of Directors and generally seek, among other things, injunctive relief prohibiting the Company and Whiting from consummating the Arrangement, an order rescinding the Arrangement Agreement and reimbursement of unspecified costs, including attorneys’ and experts’ fees and other relief. The derivative claims seek a recovery on behalf of the Company. The Company is unable to estimate a possible loss, or range of possible loss, if any, related to these lawsuits at this time. The Company believes that the claims relating to the Arrangement are without merit, does not believe that a proper demand has been made with respect to the derivative claims, and intends to defend such actions vigorously.

19