WHITING PETROLEUM CORP - FORM 8-K - EX-99.2

Attached files

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8-K - FORM 8-K - WHITING PETROLEUM CORP	d799266d8k.htm
EX-99.4 - EX-99.4 - WHITING PETROLEUM CORP	d799266dex994.htm
EX-12.2 - EX-12.2 - WHITING PETROLEUM CORP	d799266dex122.htm
EX-99.1 - EX-99.1 - WHITING PETROLEUM CORP	d799266dex991.htm
EX-23.2 - EX-23.2 - WHITING PETROLEUM CORP	d799266dex232.htm
EX-99.3 - EX-99.3 - WHITING PETROLEUM CORP	d799266dex993.htm
EX-23.1 - EX-23.1 - WHITING PETROLEUM CORP	d799266dex231.htm
EX-12.1 - EX-12.1 - WHITING PETROLEUM CORP	d799266dex121.htm

Exhibit 99.2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Kodiak Oil & Gas Corp.

We have audited the accompanying consolidated balance sheets of Kodiak Oil & Gas Corp. (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Kodiak Oil & Gas Corp. at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Kodiak Oil & Gas Corp.’s internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 27, 2014 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Denver, Colorado

February 27, 2014

KODIAK OIL & GAS CORP.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	December 31, 2013			December 31, 2012
ASSETS
Current Assets:
Cash and cash equivalents	$	90		$	24,060
Accounts receivable
Trade		108,883			35,565
Accrued sales revenues		121,843			59,875
Commodity price risk management asset		—			10,864
Inventory and prepaid expenses		11,367			17,210
Deferred tax asset, net		14,300			—

Total Current Assets		256,483			147,574

Oil and gas properties (full cost method), at cost:
Proved oil and gas properties		3,556,667			2,007,442
Unproved oil and gas properties		641,644			457,888
Equipment and facilities		27,712			20,954
Less-accumulated depletion, depreciation, amortization, and accretion		(605,700	)		(290,094	)

Net oil and gas properties		3,620,323			2,196,190

Commodity price risk management asset		1,290			2,850
Property and equipment, net of accumulated depreciation of $1,980 at December 31, 2013 and $1,113 at December 31, 2012		3,928			1,846
Deferred financing costs, net of amortization of $22,963 at December 31, 2013 and $17,995 at December 31, 2012		41,746			25,176

Total Assets	$	3,923,770		$	2,373,636

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	272,858		$	190,596
Accrued interest payable		24,425			6,090
Commodity price risk management liability		20,334			304

Total Current Liabilities		317,617			196,990

Noncurrent Liabilities:
Credit facility		708,000			295,000
Senior notes, net of accumulated amortization of bond premium of $1,024 at December 31, 2013 and $378 at December 31, 2012		1,554,976			805,622
Commodity price risk management liability		—			4,288
Deferred tax liability, net		133,700			26,800
Asset retirement obligations		16,405			9,064

Total Noncurrent Liabilities		2,413,081			1,140,774

Total Liabilities		2,730,698			1,337,764

Commitments and Contingencies—Note 14
Stockholders’ Equity:
Common stock—no par value; unlimited authorized
Issued and outstanding: 266,249,765 shares as of December 31, 2013 and 265,273,314 shares as of December 31, 2012		1,024,462			1,008,678
Retained earnings		168,610			27,194

Total Stockholders’ Equity		1,193,072			1,035,872

Total Liabilities and Stockholders’ Equity	$	3,923,770		$	2,373,636

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONSOLIDATED FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)


	For the Years Ended December 31,
	2013			2012			2011
Revenues:
Oil sales	$	858,242		$	390,425		$	115,692
Gas sales		46,370			18,265			4,294

Total revenues		904,612			408,690			119,986

Operating expenses:
Oil and gas production		190,411			85,498			26,885
Depletion, depreciation, amortization and accretion		317,223			155,634			32,068
General and administrative		47,224			34,528			19,495

Total operating expenses		554,858			275,660			78,448

Operating income		349,754			133,030			41,538
Other income (expense):
Gain (loss) on commodity price risk management activities, net		(45,028	)		44,602			(20,114	)
Interest income (expense), net		(74,245	)		(22,911	)		(18,887	)
Other income		3,535			3,663			1,338

Total other income (expense)		(115,738	)		25,354			(37,663	)

Income before income taxes		234,016			158,384			3,875
Income tax expense		92,600			26,800			—

Net income	$	141,416		$	131,584		$	3,875

Earnings per common share:
Basic	$	0.53		$	0.50		$	0.02

Diluted	$	0.53		$	0.49		$	0.02

Weighted average common shares outstanding:
Basic		265,650,733			263,531,408			197,579,298

Diluted		269,131,914			267,671,296			200,551,992

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONSOLIDATED FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)


	Common Stock Shares		Common Stock			Retained Earnings (Accumulated Deficit)			Total Stockholders’ Equity
Balance January 1, 2011:		178,168	$	407,312		$	(108,265	)	$	299,047
Issuance of stocks for cash:
—pursuant to equity offering		75,900		542,685			—			542,685
—pursuant to exercise of options		995		1,305			—			1,305
Shares issued in connection with acquisition		2,500		14,425			—			14,425
Share issuance costs		—		(27,450	)		—			(27,450	)
Restricted stock issued		424		593			—			593
Stock-based compensation		—		5,200			—			5,200
Net income		—		—			3,875			3,875

Balance December 31, 2011:		257,987	$	944,070		$	(104,390	)	$	839,680

Issuance of stocks for cash:
—pursuant to equity offering		—		—			—			—
—pursuant to exercise of options		1,425		3,654			—			3,654
Shares issued in connection with acquisition		5,056		49,798			—			49,798
Share issuance costs		—		—			—			—
Restricted stock issued		805		—			—			—
Stock-based compensation		—		11,156			—			11,156
Net income		—		—			131,584			131,584

Balance December 31, 2012:		265,273	$	1,008,678		$	27,194		$	1,035,872

Issuance of stocks for cash:
—pursuant to equity offering		—		—			—			—
—pursuant to exercise of options		729		2,446			—			2,446
Purchase of common shares		—		(2,327	)		—			(2,327	)
Share issuance costs		—		—			—			—
Restricted stock issued		248		—			—			—
Stock-based compensation		—		15,665			—			15,665
Net income		—		—			141,416			141,416

Balance December 31, 2013:		266,250	$	1,024,462		$	168,610		$	1,193,072

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONSOLIDATED FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	For the Years Ended December 31,
	2013			2012			2011
Cash flows from operating activities:
Net income	$	141,416		$	131,584		$	3,875
Reconciliation of net income to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion		317,223			155,634			32,068
Amortization of deferred financing costs and debt premium		4,322			2,588			15,029
(Gain) loss on commodity price risk management activities, net		45,028			(44,602	)		20,114
Settlements on commodity derivative instruments		(16,862	)		13,520			(3,897	)
Stock-based compensation		15,665			11,156			5,200
Deferred income taxes		92,600			26,800			—
Changes in current assets and liabilities:
Accounts receivable-trade		(73,318	)		(5,540	)		(17,507	)
Accounts receivable-accrued sales revenue		(61,968	)		(37,901	)		(17,396	)
Prepaid expenses and other		(1,961	)		6,465			(2,082	)
Accounts payable and accrued liabilities		73,122			9,350			13,075
Accrued interest payable		18,335			282			5,434
Cash held in escrow		—			3,343			—

Net cash provided by operating activities		553,602			272,679			53,913

Cash flows from investing activities:
Oil and gas properties		(1,018,537	)		(753,609	)		(232,360	)
Acquired oil and gas properties and facilities		(756,995	)		(588,420	)		(311,405	)
Sale of oil and gas properties		85,448			2,752			3,264
Equipment, facilities and other		(9,693	)		(10,176	)		(4,758	)
Well equipment inventory		(19,365	)		(28,625	)		(15,490	)
Cash held in escrow		—			30,000			(30,000	)

Net cash used in investing activities		(1,719,142	)		(1,348,078	)		(590,749	)

Cash flows from financing activities:
Borrowings under credit facilities		1,264,875			380,000			350,808
Repayments under credit facilities		(851,875	)		(185,000	)		(290,808	)
Proceeds from the issuance of senior notes		750,000			156,000			650,000
Proceeds from the issuance of common shares		2,446			2,609			543,990
Purchase of common shares		(2,327	)		—			—
Cash held in escrow		—			670,615			(673,958	)
Debt and share issuance costs		(21,549	)		(6,369	)		(62,790	)

Net cash provided by financing activities		1,141,570			1,017,855			517,242

Decrease in cash and cash equivalents		(23,970	)		(57,544	)		(19,594	)
Cash and cash equivalents at beginning of the period		24,060			81,604			101,198

Cash and cash equivalents at end of the period	$	90		$	24,060		$	81,604

Supplemental cash flow information:
Oil & gas property accrual included in accounts payable and accrued liabilities	$	162,950		$	155,385		$	52,541

Oil & gas property acquired through common stock	$	—		$	49,798		$	14,425

Cash paid for interest	$	86,244		$	66,095		$	6,898

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF

THESE CONSOLIDATED FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

NOTES TO 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 consolidated financial statements include the accounts of the Company, including 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”). In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair presentation of the consolidated financial information, have been included.

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.

Reclassifications

The Company has condensed certain line items within the current period financial statements, and certain prior period balances were reclassified to conform to the current year presentation accordingly. Such reclassifications had no impact on net income, statements of cash flows, working capital or equity previously reported.

Cash and Cash Equivalents

Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

Accounts Receivable

The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. On an on-going basis, management reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables in 2013, 2012, or 2011.

Concentration of Credit Risk

The Company’s cash and cash equivalents are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company often has balances in excess of the federally insured limits.

The Company’s receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.

The Company’s commodity derivative contracts are currently with nine counterparties. Eight of the nine counterparties to the derivative instruments are highly rated entities with corporate ratings at or exceeding A- and A3 classifications by Standard & Poor’s and Moody’s, respectively. One counterparty had a corporate rating of BBB+ and Baa1 by Standard & Poor’s and Moody’s, respectively.

Significant Customers

During the year ended December 31, 2013, 37% of the Company’s production was sold to two customers. However, the Company does not believe that the loss of a single purchaser, including these two, would materially affect the Company’s business because there are numerous other purchasers in the area in which the Company sells its production. For the years ended December 31, 2013, 2012 and 2011 purchases by the following companies exceeded 10% of the total oil and gas revenues of the company.


	For the Years Ended December 31,
	2013			2012			2011
Customer A		23	%		27	%		27	%
Customer B		14	%		4	%		—	%
Customer C		6	%		1	%		25	%
Customer D		2	%		16	%		2	%
Customer E		1	%		2	%		11	%
Customer F		—	%		17	%		—	%

Inventory and Prepaid Expenses

The cost basis of the well equipment inventory is depreciated as a component of oil and gas properties once the inventory is used in drilling operations. The Company records well equipment inventory and crude oil inventory at the lower of cost or market value. Inventory and prepaid expenses are comprised of the following (in thousands):


	For the Years Ended December 31,
	2013		2012
Well equipment inventory	$	4,832	$	12,846
Crude oil inventory		4,662		2,388
Prepaid expenses		1,873		1,976

	$	11,367	$	17,210

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

Depletion of capitalized costs of oil and gas properties is computed using the units-of-production method based upon estimated proved oil and gas reserves as determined by the Company’s engineers and prepared by independent petroleum engineers. For this purpose, Kodiak converts its petroleum products and reserves to a common unit of measure. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Costs included in the depletion base to be amortized include (a) all proved capitalized costs, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

Estimated reserve quantities and future net cash flows have the most significant impact on the Company. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company’s proved properties. Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. For additional discussion on the process used to estimate oil and gas quantities please refer to Note 15 — Supplemental Oil and Gas Reserve Information (Unaudited).

Impairment of Oil and Gas Properties

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

There were no impairment charges recognized for the years ended December 31, 2013, 2012 and 2011.

Unproved Oil and Gas Properties

Unproved property costs not subject to amortization consist primarily of leasehold costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Interest costs related to significant unproved properties that are currently undergoing the activities necessary to get them ready for their intended use are capitalized to oil and gas properties. The Company’s unproved properties are evaluated quarterly for the possibility of potential impairment. For the years ended December 31, 2013, 2012 and 2011 no impairment was recorded.

Equipment and Facilities

Equipment and facilities are recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives of the related assets, ranging from one to twenty-five years.

Property and Equipment

Other property and equipment such as office furniture and equipment, vehicles, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is recorded using the straight-line method over the estimated useful lives of three years for computer equipment, and five years for office equipment and vehicles. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Deferred Financing Costs

Deferred financing costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company’s credit facilities and Senior Notes. Deferred financing costs related to the Company’s Senior Notes are amortized to interest expense using the effective interest method over the term of the debt. Deferred financing costs related to the credit facilities are amortized to interest expense on a straight-line basis over the respective borrowing term.

Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, primarily utilizing swaps or “no premium” collars to reduce the effect of price changes on a portion of our future oil production. 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. For additional discussion on commodity derivative instruments please refer to Note 7 — Commodity Derivative Instruments.

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 approximates fair value as it bears interest at variable rates over the term of the loan. The Company’s 2019 Notes, 2021 Notes and 2022 Notes are recorded at cost and the fair value is disclosed in Note 9 — Fair Value Measurements. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.

Asset Retirement Obligation

The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time the Company makes the decision to complete the well or a well is acquired. For additional discussion on asset retirement obligations please refer to Note 8 — Asset Retirement Obligations.

Revenue Recognition

The Company recognizes revenues from the sale of crude oil and natural gas using the sales method of accounting. Revenues from the sale of crude oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. Additionally, there were no material imbalances at December 31, 2013 and 2012.

Share Based Payments

At December 31, 2013, the Company has a stock-based compensation plan that includes restricted stock shares, restricted stock units, performance awards, stock awards, and stock options issued to employees, officers and directors as more fully described in Note 11 — Share Based Payments. The Company records expense associated with the fair value of stock-based compensation in accordance with ASC 718, Stock Based Compensation. The Company records compensation expense associated with the issuance of restricted stock shares and RSUs based on the estimated fair value of these awards determined at the time of grant.

Income Taxes

Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. 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.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-11 (“ASU 2011-11”), Balance Sheet: Disclosures about Offsetting Assets and Liabilities which applies to certain items in the statement of financial position (balance sheet), and was further clarified in January 2013 by ASU 2013-01, Balance Sheet: Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarified the scope of ASU 2011-11 to derivative instruments, repurchase agreements and securities lending transactions. The effective date for the amendments is for annual periods beginning after January 1, 2013, and interim periods within those annual periods. ASU 2011-11 requires disclosures of the gross and net amounts for items eligible for offset in the balance sheet. The Company records its derivative financial instruments on a net basis by contract. The adoption of this standard had no impact on the Company’s financial position or results of operations, but did require enhanced disclosures regarding derivative instruments. Please refer to Note 7 — Commodity Derivative Instruments for the enhanced disclosures.

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

Note 3—Oil and Gas Properties

The Company’s oil and gas properties are entirely within the United States. The net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):


	For the Years Ended December 31,
	2013			2012			2011
Proved oil and gas properties	$	3,556,667		$	2,007,442		$	641,532
Unproved oil and gas properties ⁽¹⁾		641,644			457,888			298,500
Equipment and facilities		27,712			20,954			11,186

Total capitalized costs ⁽²⁾	$	4,226,023		$	2,486,284		$	951,218
Accumulated depletion, depreciation, amortization, and accretion		(605,700	)		(290,094	)		(135,586	)

Net capitalized costs	$	3,620,323		$	2,196,190		$	815,632

(1)	Unproved oil and gas properties represent unevaluated costs the Company excludes from the amortization base until proved reserves are established or impairment is determined. The Company estimates that the remaining costs will be evaluated within 3 to 5 years.

(2)	Includes accumulated interest capitalized of $89.5 million, $54.9 million, and $8.9 million as of December 31, 2013, 2012, and 2011, respectively.

The following table presents information regarding the Company’s net costs incurred in oil and natural gas property acquisition, exploration and development activities (in thousands):


	For the Years Ended December 31,
	2013		2012		2011
Property Acquisition costs:
Proved	$	455,911	$	322,835	$	152,538
Unproved		301,322		330,912		182,878
Exploration costs		—		—		—
Development costs		1,061,198		874,303		274,293

Total	$	1,818,431	$	1,528,050	$	609,709

Total excluding asset retirement obligation	$	1,811,827	$	1,523,088	$	608,102

Depletion expense related to the proved properties per equivalent BOE of production for the years ended December 31, 2013, 2012 and 2011 were $29.80, $29.62 and $22.40, respectively (unaudited).

The following table sets forth a summary of oil and gas property costs, which substantially consists of acquisition costs, not being amortized as of December 31, 2013 by the year in which such costs were incurred (in thousands):


	Unproved Additions by Year
Prior	$	36,752
2011		78,036
2012		230,334
2013		296,522

Total	$	641,644

Note 4—Acquisitions and Divestitures

July 2013 Acquisition

On July 12, 2013, the Company’s subsidiary, Kodiak Williston, LLC, acquired an unaffiliated oil and gas company’s interests in approximately 42,000 net acres of Williston Basin leaseholds, and related producing properties located primarily in McKenzie and southern Williams Counties, North Dakota, along with various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract (the “July 2013 Acquisition”). The seller received aggregate consideration of approximately $731.8 million in cash. The effective date for the acquisition was March 1, 2013, with purchase price adjustments calculated as of the closing date on July 12, 2013. The acquisition provided strategic additions adjacent to the Company’s core project area and the acquired producing wells contributed revenue of $73.2 million to the Company for the year ended December 31, 2013. Transaction costs related to the acquisition incurred through December 31, 2013 were approximately $185,000 and are recorded in the statement of operations within the general and administrative expenses 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. 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):


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

Total consideration given	$	731,785

Allocation of Purchase Price
Proved oil and gas properties	$	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

January 2012 Acquisition

On January 10, 2012, the Company acquired two separate private, unaffiliated oil and gas company’s interests in approximately 50,000 net acres of Williston Basin leaseholds, and related producing properties located primarily in McKenzie and Williams Counties, North Dakota, along with various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract for a combination of cash and stock. The sellers received an aggregate of 5.1 million shares of the Company’s common stock valued at approximately $49.8 million and cash consideration of approximately $588.4 million. The effective date for the acquisition was September 1, 2011, with purchase price adjustments calculated as of the closing date on January 10, 2012. The acquisition provided strategic additions adjacent to the Company’s core project area and the acquired producing wells contributed revenue of $26.0 million and $33.6 million to the Company for the years ended December 31, 2013 and 2012, respectively. Total transaction costs related to the acquisition were approximately $295,000, of which $85,000 and $210,000 were recorded in the statement of operations within the general and administrative expenses line item for the years ended December 31, 2012 and 2011, respectively. No material costs were incurred for the issuance of the 5.1 million shares of common stock.


Purchase Price	January 10, 2012
Consideration given
Cash from senior notes	$	588,420
Kodiak Oil & Gas Corp. common stock (5,055,612 shares)		49,798	*

Total consideration given	$	638,218

Allocation of Purchase Price
Proved oil and gas properties		322,835
Unproved oil and gas properties		313,053
Equipment and facilities		7,025

Total fair value of oil and gas properties acquired	$	642,913
Working capital		(3,895	)
Asset retirement obligation		(800	)

Fair value of net assets acquired	$	638,218

Working capital acquired was estimated as follows:
Accounts receivable		7,200
Prepaid completion costs		465
Crude oil inventory		540
Accrued liabilities		(12,100	)

Total working capital	$	(3,895	)

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

October 2011 Acquisition

On October 28, 2011, the Company acquired a private, unaffiliated oil and gas company’s interests in approximately 13,400 net acres of Williston Basin leaseholds, and related producing properties located primarily in Williams County, North Dakota along with various other related rights, permits, contracts, equipment and other assets. The seller received cash consideration of approximately $248.2 million. The effective date for the acquisition was August 1, 2011, with purchase price adjustments calculated as of the closing date on October 28, 2011. The acquisition provided strategic additions adjacent to the Company’s core project area and the acquired producing wells contributed revenue of $18.7 million and $27.2 million to the Company for the years ended December 31, 2013 and 2012, respectively. Total transaction costs related to the acquisition were approximately $200,000, all of which was recorded in the statement of operations within the general and administrative expenses line item for the year ended December 31, 2011.

The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of October 28, 2011. In February 2012, the Company completed the transaction’s post-closing settlement resulting in no material changes. Of the $248.2 million purchase price, $149.7 million was allocated to proved oil and gas properties, $90.2 million was allocated to unproved oil and gas properties and the remaining $8.3 million was allocated to working capital and asset retirement obligation adjustments.

June 2011 Acquisition

On June 30, 2011, the Company acquired a private, unaffiliated oil and gas company’s interests in approximately 25,000 net acres of Williston Basin leaseholds and related producing properties located in McKenzie County, North Dakota along with various other related rights, permits, contracts, equipment and other assets for a combination of cash and stock. The seller received 2.5 million shares of the Company’s common stock valued at approximately $14.4 million and cash consideration of approximately $71.5 million. The effective date for the acquisition was April 1, 2011, with purchase price adjustments calculated as of the closing date on June 30, 2011. The acquisition provided strategic additions to the Company’s core positions in Koala, Smokey and Grizzly Project areas and the acquired producing wells contributed revenue of $1.1 million and $1.5 million to the Company for the years ended December 31, 2013 and 2012, respectively. Total transaction costs related to the acquisition were approximately $265,000, all of which were recorded in the statement of operations, within the general and administrative expenses line item, for the year ended December 31, 2011. Costs of $85,000 for issuing and registering with the SEC for the resale of 2.5 million shares of common stock were charged to common stock in 2011.

The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 30, 2011. In September 2011, the Company completed the transaction’s post-closing settlement resulting in no material changes. Of the $85.9 million purchase price, $8.0 million was allocated to proved oil and gas properties, $77.8 million was allocated to unproved oil and gas properties and the remaining $100,000 was working capital and asset retirement obligation adjustments.

Other Acquisitions, Divestitures, and Trades

During 2013, through various acquisitions, divestitures and trades, the Company divested approximately 3,700 net acres in the Williston Basin. As a result of certain acquisitions that were accounted for as Business Combinations, the Company recorded $41.8 million to proved properties and $4.1 million to unproved properties based on the estimated values of assets acquired and liabilities assumed. These acquisitions contributed no material revenue to the Company for the years ended December 31, 2013 and 2012, respectively. As these acquisitions were deemed insignificant, no pro forma financial information is provided. Net proceeds from all of the acquisitions and divestitures were approximately $34.8 million and the gross value of the non-monetary transactions was not significant. As a result of these transactions, the Company was able to divest or trade out of non-operated units and increase its working interest in operated units.

Additionally, in February 2014, the Company divested approximately 19,700 net acres in the Williston Basin for cash proceeds of $69.2 million.

Pro Forma Financial Information

For the years ended December 31, 2013 and 2012, the following pro forma financial information represents the combined results for the Company and the properties acquired in July 2013 as if the acquisition and related financing had occurred on January 1, 2012 and for the properties acquired in January 2012 as if the acquisition and related financing had occurred on January 1, 2011. For the year ended December 31, 2011, the following pro forma financial information represents the combined results for the Company and the properties acquired in January 2012 as if the acquisition and related financing had occurred on January 1, 2011, and for the properties acquired in October 2011 and June 2011 as if these acquisitions and related financing had occurred on January 1, 2011 (all in thousands, except per share data). For purposes of the pro forma it was assumed that the Company’s credit facility was used to finance the July 2013 Acquisition and the senior notes issued in November 2011 were used to fund the January 2012 Acquisition and that the stand-by bridge previously arranged was not utilized. Additionally, it was assumed that common stock was used to fund the October 2011 and June 2011 acquisitions. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $24.2 million, $25.1 million and $27.7 million and amortization of financing costs of $816,000, $816,000 and $1.5 million for the years ended December 31, 2013, 2012 and 2011, respectively. The pro forma information includes the effects of incremental interest expense on acquisition financing of $6.1 million and $17.8 million for the years ended December 31, 2013 and 2012, respectively. For the year ended December 31, 2011, there were pro forma adjustments of $15.5 million reducing interest expense. The pro forma financial information includes total capitalization of interest expense of $38.3 million, $46.6 million and $59.5 million for the years ended December 31, 2013, 2012 and 2011 respectively. The pro forma information includes the effects of adjustments for income tax expense of $12.3 million and $9.1 million for the years ended December 31, 2013 and 2012, respectively.

The following pro forma results (in thousands) do not include any cost savings or other synergies that may result from the acquisitions or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisitions had been completed as of the beginning of the period, nor are they necessarily indicative of future results.


	For the Years Ended December 31,
	2013		2012		2011
Operating revenues	$	990,552	$	494,367	$	187,842

Net income	$	160,296	$	146,212	$	43,714

Earnings per common share
Basic	$	0.60	$	0.55	$	0.18

Diluted	$	0.60	$	0.55	$	0.18

Note 5—Long-Term Debt

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


	At December 31,
	2013		2012
Credit Facility due April 2018	$	708,000	$	295,000
2019 Notes due December 2019		800,000		800,000
Unamortized Premium on 2019 Notes		4,976		5,622
2021 Notes due January 2021		350,000		—
2022 Notes due February 2022		400,000		—

Total Long-Term Debt	$	2,262,976	$	1,100,622
Less: Current Portion of Long Term Debt		—		—

Total Long-Term Debt, Net of Current Portion	$	2,262,976	$	1,100,622

Credit Facility

Kodiak Oil & Gas (USA) Inc. (the “Borrower”), a wholly-owned subsidiary of Kodiak Oil & Gas Corp., 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 December 31, 2013, 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.

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


Borrowing Base Utilization Percentage	<25.0%			³25.0% <50.0%			³50.0% <75.0%			³75.0% <90.0%			³90.0%
Eurodollar Loans		1.50	%		1.75	%		2.00	%		2.25	%		2.50	%
ABR Loans		0.50	%		0.75	%		1.00	%		1.25	%		1.50	%
Commitment Fee Rate		0.375	%		0.375	%		0.50	%		0.50	%		0.50	%

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

The credit facility also contains financial covenants requiring the Borrower to comply with a current ratio of consolidated current assets (including unused borrowing capacity) to consolidated current liabilities of not less than 1.0:1.0 and to maintain, on the last day of each quarter, a ratio of total debt to EBITDAX of not greater than 4.0 to 1.0. The Company was in compliance with all financial covenants under the credit facility as of December 31, 2013, and through the filing of this report.

As of December 31, 2013, the Company had $708.0 million in outstanding borrowings under the credit facility and as such, the available credit under the credit facility at that date was $642.0 million. Subsequent to December 31, 2013, the Company paid down $8.0 million on the credit facility, bringing the outstanding balance as of the date of this filing under the credit facility to $700.0 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.

Second Lien Credit Agreement

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

Senior Notes

In November 2011 the Company issued at par $650.0 million 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 and repay outstanding borrowings under its credit facility and second lien credit agreement and for general corporate purposes.

In January 2013, the Company issued at par $350.0 million principal amount of 5.50% Senior Notes due January 15, 2021 (the “2021 Notes”). The 2021 Notes bear an annual interest rate of 5.50%. 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 December 31, 2013, and through the filing of this report.

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

On November 16, 2012, the Company closed a registered exchange offer with respect to the 2019 Notes pursuant to which all of the holders of the privately placed 2019 Notes exchanged their notes for SEC-registered 2019 Notes. On December 3, 2013, the Company closed a registered exchange offer with respect to the 2021 Notes and 2022 Notes, pursuant to which all holders of the privately placed 2021 Notes and 2022 Notes exchanged their notes for SEC-registered 2021 Notes and 2022 Notes, respectively.

Deferred Financing Costs

As of December 31, 2013, the Company had deferred financing costs of $41.7 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 years ended December 31, 2013, 2012, and 2011, the Company recorded amortization expense of $5.0 million, $3.0 million, and $15.0 million, respectively.

Interest Incurred On Long-Term Debt

For the years ended December 31, 2013, 2012, and 2011, the Company incurred interest expense on long-term debt of $104.6 million, $63.4 million, and $12.4 million, respectively. Of the total interest incurred, the Company capitalized interest costs of $34.6 million, $46.0 million, and $8.4 million for the years ended December 31, 2013, 2012, and 2011, respectively. Additionally, for the years ended December 31, 2013 and 2012, interest expense was reduced for the amortization of the bond premium in the amount of $646,000 and $378,000, respectively.

Note 6—Income Taxes

The Company’s provision for income taxes consists of the following (in thousands):


	For the Years Ended December 31,
	2013		2012		2011
Current income tax expense (U.S. and Canada)	$	—	$	—	$	—
Deferred income tax expense
U.S.	$	92,600	$	26,800	$	—
Canada		—		—		—

Total deferred income tax expense		92,600		26,800		—

Total income tax expense	$	92,600	$	26,800	$	—

The Company’s effective income tax rate differs from amounts that would result from applying the United States federal statutory income tax rate of 35% to income before income taxes as follows:


	For the Years Ended December 31,
	2013			2012			2011
Federal		35.00	%		35.00	%		35.00	%
State		2.17	%		2.43	%		2.23	%
Other		(0.33	)%		2.51	%		0.00	%
Change in valuation allowances		2.73	%		(23.00	)%		(37.23	)%

Net		39.57	%		16.94	%		0.00	%

The Company’s principal components of deferred income tax assets and liabilities are as follows (in thousands):


	For the Years Ended December 31,
	2013			2012			2011
Deferred Income Tax Assets (Liabilities):
U.S. net operating loss carryovers	$	67,050		$	51,176		$	40,378
Stock-based compensation		4,037			5,988			5,225
Oil and gas properties		(204,035	)		(79,369	)		(17,543	)
Canadian net operating losses and issuance costs		17,462			11,070			8,600
Derivatives (Mark to market)		7,079			(3,414	)		8,175
Other		6,469			(1,181	)		(645	)

		(101,938	)		(15,730	)		44,190
Valuation allowance on United States tax assets		—			—			(35,590	)
Valuation allowance on Canadian tax assets		(17,462	)		(11,070	)		(8,600	)

Deferred income tax asset (liability), net	$	(119,400	)	$	(26,800	)	$	—

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 an assessment as to the future utilization of deferred tax assets. The Company continues to provide a full valuation allowance on the Canadian net deferred tax assets as ultimate realization of these deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. As the Company does not have revenue generating assets in Canada, the Company does not expect to utilize the Canadian net deferred tax assets. As of March 31, 2012 the Company concluded that it was more likely than not to be able to realize the benefits of its U.S. deferred tax assets and determined it was appropriate, at that time, to release the U.S. valuation allowance against its U.S. deferred tax assets. This decision was based on the fact that for the preceding three-year period the Company had reported positive cumulative net income. 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.

Net Operating Losses

As of December 31, 2013, the Company estimates its cumulative net operating loss (“NOL”) at approximately $271.8 million which may be carried forward to reduce taxable income in future years. As of December 31, 2013, the Company had U.S. federal NOL carryovers of $204.3 million for U.S. federal income tax purposes and $181.2 million for financial reporting purposes. The difference of $23.1 million is attributable to tax deductions related to equity compensation in excess of equity compensation recognized for financial reporting purposes. In addition, the Company has $67.5 million in NOLs related to its Canadian tax filings. If unused, the U.S. federal NOLs will begin to expire between the years 2023 and 2033 and the Canadian NOLs will expire between the years 2014 and 2033.

The Tax Reform Act of 1986 contains provisions that limit the utilization of net operating loss carryforwards if there has been a change in ownership as described in Internal Revenue Code Section 382. The Company analyzed potential limitations under IRC Section 382 and determined there are no limitations to its net operating loss carryforwards as of December 31, 2013.

Accounting for Uncertainty in Income Taxes

As of December 31, 2013, the Company believes that it has no liability for uncertain tax positions. If the Company were to determine there were any uncertain tax positions, the Company would recognize the liability and related interest and penalties within income tax expense. As of December 31, 2013, the Company had no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in Canada and U.S. federal jurisdiction and various states. There are currently no Canadian or U.S. federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service, state or local tax authorities for tax years ended on or before December 31, 2009 or Canadian tax examinations by the Canadian Revenue Agency for tax years ended on or before December 31, 2001. Although certain tax years are closed under the statute of limitations, tax authorities can still adjust tax losses being carried forward to open tax years.

Note 7—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 same counterparty is required to pay the Company if the settlement price is less than the strike price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with 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 commodity derivative contracts as of December 31, 2013 are summarized below:

Collars

Basis ⁽¹⁾

Quantity (Bbl/d)

Strike Price
($/Bbl)

January 1, 2014—December 31, 2015

NYMEX

300 - 425

85.00 - $102.75


Swaps	Basis ⁽¹⁾		Average Quantity (Bbl/d)		Average Swap Price ($/Bbl)
2014 Total		NYMEX		25,800	$	93.41
2015 Total		NYMEX		3,625	$	88.77

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

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


		As of 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	)	$	—

		As of December 31, 2012
Underlying Commodity	Location on Balance Sheet	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Consolidated Balance Sheet
Crude oil derivative contract	Current assets	$	16,912	$	(6,048	)	$	10,864
Crude oil derivative contract	Noncurrent assets	$	5,455	$	(2,605	)	$	2,850
Crude oil derivative contract	Current liabilities	$	6,352	$	(6,048	)	$	304
Crude oil derivative contract	Noncurrent liabilities	$	6,893	$	(2,605	)	$	4,288

The Company recognized a net loss on commodity price risk management activities of $45.0 million for the year ended December 31, 2013 and a net gain on commodity price risk management activities of $44.6 million for the year ended December 31, 2012.

Note 8—Asset Retirement Obligations

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

The following table summarizes the activities of the Company’s asset retirement obligation for the years ended December 31, 2013 and 2012 (in thousands):


	For the Years Ended December 31,
	2013			2012
Balance beginning of period	$	9,064		$	3,627
Liabilities incurred or acquired		7,181			4,537
Liabilities settled		(890	)		(58	)
Revisions in estimated cash flows		—			405
Accretion expense		1,050			553

Balance end of period	$	16,405		$	9,064

Note 9—Fair Value Measurements

ASC Topic 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

•

Level 1: Quoted prices are available in active markets for identical assets or liabilities;

•

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;

•

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

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

The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 8 - Asset Retirement Obligations, and the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 4 - 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.

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 December 31, 2013 and 2012 by level within the fair value hierarchy (in thousands):


	Fair Value Measurements at December 31, 2013 Using
	Level 1		Level 2		Level 3		Total
Financial Assets and Liabilities:
Commodity price risk management asset	$	—	$	1,290	$	—	$	1,290
Commodity price risk management liability	$	—	$	20,334	$	—	$	20,334


	Fair Value Measurements at December 31, 2012 Using
	Level 1		Level 2		Level 3		Total
Financial Assets and Liabilities:
Commodity price risk management asset	$	—	$	13,714	$	—	$	13,714
Commodity price risk management liability	$	—	$	4,592	$	—	$	4,592

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

Commodity Derivative Instruments

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At December 31, 2013 and 2012, derivative instruments utilized by the Company consist of both “no premium” collars and swaps. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents and accounts receivable, accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair value of the 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.


	At December 31, 2013				At December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Credit facility	$	708,000	$	708,000	$	295,000	$	295,000
2019 Notes	$	804,976	$	888,000	$	805,622	$	890,000
2021 Notes	$	350,000	$	350,438	$	—	$	—
2022 Notes	$	400,000	$	398,000	$	—	$	—

Note 10—Common Stock

In January 2012, the Company issued 5,055,612 shares of common stock valued at approximately $49.8 million to two separate private, unaffiliated oil and gas companies as part of the consideration for the oil and gas properties acquired in January 2012. Please refer to Note 4 - Acquisitions and Divestitures for additional discussion.

In November 2011, the Company issued 48,300,000 shares of common stock in a public offering, including the full exercise of the underwriters’ over-allotment option of 6,300,000 shares. All shares were sold at a price of $7.75 per share. The net proceeds of the offering, after deducting underwriting discounts, commissions and other offering expenses, were approximately $355.5 million. The net proceeds were used to repay all borrowing under the Company’s second lien credit agreement in January 2012 and repay all outstanding borrowing under the credit facility at that time.

In July 2011, the Company issued 27,600,000 shares of common stock in a public offering, which included the full exercise of the underwriters’ over-allotment option of 3,600,000 shares. All shares were sold at a price of $6.10 per share. The net proceeds of the offering, after deducting underwriting discounts and commissions and Kodiak’s estimated offering expenses, were approximately $159.8 million. The Company used $60.0 million of the net proceeds from the offering to repay debt outstanding under the credit facility.

In June 2011, the Company issued 2,500,000 shares of common stock valued at approximately $14.4 million to a private, unaffiliated oil and gas company as part of the consideration for the oil and gas properties acquired in June 2011. Please refer to Note 4 - Acquisitions and Divestitures for additional discussion.

Note 11—Share Based Payments

The Company has granted various equity-based awards to directors, officers, and employees of the Company under the 2007 Stock Incentive Plan, amended on June 3, 2010 and further amended on June 15, 2011 (as so amended, the “Plan”). The Plan authorizes the Company to issue stock options, stock appreciation rights, restricted stock and restricted stock units, performance awards, other stock grants and other stock-based awards to any employee, consultant, independent contractor, director or officer providing services to the Company or to an affiliate of the Company. The maximum number of shares of common stock available for issuance under the Plan is equal to 14% of the Company’s issued and outstanding shares of common stock, as calculated on January 1 of each respective year, subject to adjustment as provided in the Plan. As of January 1, 2013, the maximum number of shares issuable under the Plan, including those previously issued thereunder, was approximately 37.1 million shares.

Stock Options

Total compensation expense related to the stock options of $8.1 million, $6.4 million, and $3.6 million was recognized for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, there was $7.8 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted average period of 2.0 years.

Compensation expense related to stock options is calculated using the Black Scholes-Merton valuation model.

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


	For the Years Ended December 31,
	2013			2012			2011
Risk free rates		0.88-2.14	%		0.78-1.48	%		1.06 - 2.57	%
Dividend yield		—	%		—	%		—	%
Expected volatility		80.04 - 85.08	%		85.23 - 90.25	%		90.43 - 94.97	%
Weighted average expected stock option life		5.81 years			5.85 years			6.01 years

The weighted average fair value at the date of grant for stock options granted is as follows:
Weighted average fair value per share	$	6.80		$	6.58		$	5.10
Total options granted		1,850,900			1,159,500			1,712,500
Total weighted average fair value of options granted	$	12,586,120		$	7,629,510		$	8,733,750

A summary of the stock options outstanding is as follows:


	Number of Options			Weighted Average Exercise Price
Balance outstanding at January 1, 2011:		6,489,917		$	2.73
Granted		1,712,500			6.74
Forfeited		(616,525	)		3.61
Exercised		(994,734	)		2.88

Balance outstanding at December 31, 2011:		6,591,158		$	3.77

Granted		1,159,500			9.08
Forfeited		(620,029	)		6.06
Exercised		(1,424,678	)		2.85

Balance outstanding at December 31, 2012:		5,705,951		$	4.83

Granted		1,850,900			9.79
Forfeited		(727,952	)		6.70
Exercised		(728,744	)		4.41

Balance outstanding at December 31, 2013:		6,100,155		$	6.12

Options exercisable at December 31, 2013:		3,719,988		$	4.20

The following table summarizes information about stock options outstanding at December 31, 2013:


	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number of Options Outstanding		Weighted Average Remaining Contractual Life (Years)		Weighted Average Exercise Price		Number of Options Exercisable		Weighted Average Remaining Contractual Life (Years)		Weighted Average Exercise Price
$0.36-$2.00		738,448		1.9	$	0.91		738,448		1.9	$	0.91
$2.01-$4.00		1,671,207		4.1	$	3.04		1,671,207		4.1	$	3.04
$4.01-$6.00		318,000		7.3	$	5.06		229,000		7.3	$	5.01
$6.01-$8.00		927,500		7.3	$	6.81		508,500		6.7	$	6.63
$8.01-$10.00		1,897,000		8.7	$	9.16		566,000		8.1	$	9.35
$10.01-$12.00		345,000		9.7	$	10.68		6,833		8.3	$	10.11
$12.01-$13.31		203,000		9.8	$	12.78		—		0.0	$	0.00

		6,100,155		6.4	$	6.12		3,719,988		4.8	$	4.20

The aggregate intrinsic value of vested and exercisable options as of December 31, 2013 was $26.1 million. The aggregate intrinsic value of options vested and expected to vest as of December 31, 2013 was $31.1 million. The intrinsic value of is based on the Company’s December 31, 2013 closing common stock price of $11.21. 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 2013 was $6.6 million.

Restricted Stock Units and Restricted Stock

Total compensation expense related to restricted stock units (“RSUs”) and restricted stock of $7.6 million, $4.8 million, and $1.6 million was recognized for the years ended December 31, 2013, 2012, and 2011, respectively. As of December 31, 2013, there was $19.8 million of total unrecognized compensation cost related to the RSUs and restricted stock, which is expected to be amortized over a weighted average period of 2.3 years.

During the first and fourth quarter of 2013, the Company awarded 36,000 and 31,500 shares of restricted stock to its Board of Directors pursuant to the Plan, respectively. These restricted stock shares vest over a four year period and the Company began recognizing compensation expense related to these grants in the quarter they were awarded. The Company recognizes compensation cost for these grants on a straight-line basis over the requisite service period for the entire award. The fair value of restricted stock is based on the stock price on the grant date and the Company assumes a 0.6% annual forfeiture rate.

In the fourth quarter 2013, the Company awarded 1,221,966 performance based RSUs to officers pursuant to the Plan. Subject to the satisfaction of certain 2014 performance-based conditions, the RSUs vest one-quarter per year over a four year service period and the Company began recognizing compensation expense related to these grants beginning in the fourth quarter 2013 over the vesting period. The Company recognizes compensation cost for performance based grants on a tranche level basis over the requisite service period for the entire award. Each quarter, the Company evaluates the actual performance results compared to the performance metrics and estimates the probability of the metrics being satisfied. The Company adjusts the number of shares expected to be granted and related expense based on its assessment. The Company is currently assuming that the maximum number of shares will be granted and expensing accordingly. The fair value of the RSUs granted is based on the stock price on the grant date and the Company assumed a 0.6% annual forfeiture rate.

As of December 31, 2013, there were 1,266,209 unvested performance based RSUs, 1,221,966 RSU’s that may be issued subject to performance based metrics and 125,000 unvested restricted stock shares with a combined weighted average grant date fair value of $10.18 per share. The total fair value vested during 2013 was $4.8 million. A summary of the RSUs and restricted stock shares outstanding is as follows:


	Number of Shares			Weighted Average Grant Date Fair Value
Non-vested restricted stock and RSUs at January 1, 2011		183,000		$	6.47
Granted		1,025,085			8.51
Forfeited		—			—
Vested		(199,974	)		6.78

Non-vested restricted stock and RSUs at December 31, 2011		1,008,111		$	8.48

Granted		1,107,873			9.18
Forfeited		—			—
Vested		(286,403	)		8.30

Non-vested restricted stock and RSUs at December 31, 2012		1,829,581		$	8.93

Granted		1,324,466			11.34
Forfeited		—			—
Vested		(540,872	)		8.79

Non-vested restricted stock and RSUs at December 31, 2013		2,613,175		$	10.18

Note 12—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 11—Share Based Payments under the heading Restricted Stock Units and Restricted Stock for additional discussion.

The table below sets forth the computations of basic and diluted net income per share for the years ended December 31, 2013, 2012, and 2011 (in thousands, except per share data):


	For the Years Ended December 31,
	2013			2012			2011
Basic net income	$	141,416		$	131,584		$	3,875
Income allocable to participating securities		(48	)		(15	)		(1	)

Diluted net income	$	141,368		$	131,569		$	3,874

Basic weighted average common shares outstanding		265,650,733			263,531,408			197,579,298
Effect of dilutive securities
Options to purchase common shares		5,552,155			5,092,451			5,567,158
Assumed treasury shares purchased		(3,698,202	)		(1,696,667	)		(2,691,509	)
Unvested restricted stock units		1,627,228			744,104			97,045

Diluted weighted average common shares outstanding		269,131,914			267,671,296			200,551,992

Basic earnings per share	$	0.53		$	0.50		$	0.02

Diluted earnings per share	$	0.53		$	0.49		$	0.02

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

For the Years Ended December 31,

2013

2012

2011

Anti-dilutive shares

548,000

613,500

1,121,045

Note 13—Benefit Plans

401(k) Plan

In 2008 the Company established a 401(k) plan for the benefit of its employees. Eligible employees may make voluntary contributions not exceeding statutory limitations to the plan. The Company matches 100% of employee contributions up to 3% of the employee’s salary and 50% of an additional 2% of employee contributions. The Company’s matching contributions are 100% vested upon participation. The matching contribution recorded in 2013 and 2012, respectively was $480,000 and $346,000.

Other Company Benefits

The Company provides a health, dental, vision, life, and disability insurance benefit to all regular full-time employees.

Note 14—Commitments and Contingencies

Leases

The Company leases office space in Denver, Colorado and Williston and Dickinson, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on October 31, 2016. The Williston and Dickinson, North Dakota leases expire on May 31, 2014 and December 31, 2014, respectively. Total rental commitments under non-cancelable leases for office space were $3.2 million at December 31, 2013. The future minimum lease payments under these non-cancelable leases are as follows: $1.1 million in 2014, $1.1 million in 2015, $1.0 million in 2016, $0 in 2017, and $0 in 2018.

Drilling Rigs

As of December 31, 2013, the Company was subject to commitments on all seven of its drilling rigs. Four of the contracts expire in 2014, one expires in 2015 and two expire in 2016. In the event of early termination under all of these contracts, the Company would be obligated to pay an aggregate amount of approximately $64.1 million as of December 31, 2013 as required under the varying terms of such contracts.

Guarantees

As of December 31, 2013, 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 5—Long-Term Debt). Finally, as of December 31, 2013, the Company’s wholly-owned subsidiaries did 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.

Note 15—Supplemental Oil and Gas Reserve Information (Unaudited)

Oil and Natural Gas Reserve Quantities (Unaudited)

The reserves at December 31, 2013, 2012 and 2011 presented below were prepared by the independent engineering firm Netherland, Sewell & Associates, Inc. All reserves are located within the continental United States. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following table sets forth information for the years ended December 31, 2013, 2012 and 2011 with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves:


	Crude Oil (MBbls)			Natural Gas (MMcf)
December 31, 2010		10,010.4			8,960.1
Revisions of previous estimates		1,983.2			268.5
Purchase of reserves		7,104.8			4,995.4
Extensions, discoveries, and other additions		17,821.8			12,108.6
Sale of reserves		(0.2	)		(270.7	)
Production		(1,344.5	)		(522.7	)

December 31, 2011		35,575.5			25,539.2
Revisions of previous estimates		1,965.2			17,954.8
Purchase of reserves		10,510.6			8,283.8
Extensions, discoveries, and other additions		37,582.6			34,647.8
Sale of reserves		—			—
Production		(4,704.1	)		(3,302.0	)

December 31, 2012		80,929.8			83,123.6
Revisions of previous estimates		898.3			16,044.1
Purchase of reserves		22,578.9			16,917.7
Extensions, discoveries, and other additions		44,818.0			66,494.8
Sale of reserves		(1,528.8	)		(1,353.3	)
Production		(9,439.2	)		(7,241.8	)

December 31, 2013		138,257.0			173,985.1

Proved Developed Reserves, included above:
Balance, December 31, 2010		3,756.4			3,653.0

Balance, December 31, 2011		13,178.8			8,956.8

Balance, December 31, 2012		36,158.0			41,870.3

Balance, December 31, 2013		63,934.1			78,822.7

Proved Undeveloped Reserves, included above:
Balance, December 31, 2010		6,254.0			5,307.1

Balance, December 31, 2011		22,396.7			16,582.4

Balance, December 31, 2012		44,771.8			41,253.3

Balance, December 31, 2013		74,322.9			95,162.4

•

The values for the 2013 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31, 2013 crude oil price of $96.91 per barrel (West Texas Intermediate price) and natural gas price of $3.51 per MMBtu (Questar Rocky Mountains price) or $3.75 per MMBtu (Northern Ventura price). All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2013 was $89.24 per barrel of oil and $4.96 per Mcf for natural gas.

•

The values for the 2012 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31, 2012 crude oil price of $94.68 per barrel (West Texas Intermediate price) and natural gas price of $2.58 per MMBtu (Questar Rocky Mountains price) or $2.77 per MMBtu (Northern Ventura price). All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2012 was $82.84 per barrel of oil and $5.73 per Mcf for natural gas.

•

The values for the 2011 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31, 2011 crude oil price of $95.99 per barrel (West Texas Intermediate price) and natural gas price of $3.94 per MMBtu (Questar Rocky Mountains price) or $4.17 per MMBtu (Northern Ventura price). All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2011 was $88.40 per barrel of oil and $5.50 per Mcf for natural gas.

For the year ended December 31, 2013, the Company had upward revisions of previous estimates of 898.3 MBbls and 16,044.1 MMcf. These revisions are primarily the result of well performance. As a result of ongoing drilling and completion activities during 2013, the Company reported extensions, discoveries, and other additions of 44,818.0 MBbls and 66,494.8 MMcf. Additionally, in 2013 through acquisition and divestitures, the Company purchased reserves of 22,578.9 MMbls and 16,917.7 MMcf and sold reserves of 1,528.8 MMbls and 1,353.3 MMcf., respectively

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The Company follows the guidelines prescribed in ASC Topic 932, Extractive Activities—Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil and natural gas reserve disclosures, standardized measures of discounted future net cash flows from proved oil and natural gas reserves and the reconciliations of standardized measures from year to year.

The information is based on estimates of proved reserves attributable to the Company’s interest in oil and natural gas properties as of December 31 of the years presented. These estimates were prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions. (2) The estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves for reserves. (3) The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred. (4) Future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves. (5) Future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The following summary sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):


	For the Years Ended December 31,
	2013			2012			2011
Future oil and gas sales	$	13,201,771		$	7,179,856		$	3,285,461
Future production costs		(4,467,923	)		(2,078,147	)		(962,680	)
Future development costs		(1,889,222	)		(1,072,131	)		(504,762	)
Future income tax expense		(1,388,913	)		(694,877	)		(431,650	)

Future net cash flows		5,455,713			3,334,701			1,386,369

10% annual discount		(2,672,875	)		(1,726,174	)		(726,394	)
Standardized measure of discounted future net cash flows ⁽¹⁾	$	2,782,838		$	1,608,527		$	659,975

(1)

The Company’s calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all years reported. For purposes of the Standardized Measure calculation, it was assumed that all of our NOLs will be realized within future carryforward periods. All of the Company’s operations, and resulting NOLs, are attributable to our oil and gas assets.

The following are the principal sources of change in the Standardized Measure (in thousands):


	For the Years Ended December 31,
	2013			2012			2011
Balance at beginning of period	$	1,608,527		$	659,975		$	154,568
Sales of oil and gas, net		(714,201	)		(323,192	)		(93,102	)
Net change in prices and production costs		94,975			(23,839	)		92,165
Net change in future development costs		41,338			(14,706	)		(8,563	)
Extensions and discoveries		962,961			710,912			424,635
Acquisition of reserves		641,730			267,932			165,152
Sale of reserves		(44,973	)		—			(29	)
Revisions of previous quantity estimates		74,287			100,376			43,311
Previously estimated development costs incurred		332,510			265,174			34,236
Net change in income taxes		(384,805	)		(119,847	)		(184,146	)
Accretion of discount		191,908			111,127			16,113
Other		(21,419	)		(25,385	)		15,635

Balance at end of period	$	2,782,838		$	1,608,527		$	659,975

Note 16—Quarterly Financial Information (Unaudited):

The Company’s quarterly financial information for the years ended December 31, 2013 and 2012 is as follows (in thousands, except share data):


	For the Year Ended December 31, 2013
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total revenue	$	165,050		$	173,478		$	299,592		$	266,492
Income from operations ⁽¹⁾	$	71,674		$	73,538		$	143,366		$	108,400
Other income (expense)	$	(29,128	)	$	7,138		$	(80,156	)	$	(13,592	)
Net income	$	19,444		$	44,250		$	31,150		$	46,572
Basic earnings per share	$	0.07		$	0.17		$	0.12		$	0.17
Diluted earnings per share	$	0.07		$	0.17		$	0.12		$	0.17
Net cash provided by operating activities	$	114,573		$	118,331		$	152,631		$	168,067
Net cash used in investing activities	$	(279,870	)	$	(300,760	)	$	(884,356	)	$	(254,156	)
Net cash provided by financing activities	$	147,822		$	189,916		$	735,971		$	67,861

	For the Year Ended December 31, 2012
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total revenue	$	79,936		$	85,768		$	112,140		$	130,846
Income from operations ⁽¹⁾	$	36,341		$	34,379		$	45,470		$	51,368
Other income (expense)	$	(26,699	)	$	92,755		$	(36,848	)	$	(3,854	)
Net income	$	1,744		$	93,072		$	3,476		$	33,292
Basic earnings per share	$	0.01		$	0.35		$	0.01		$	0.13
Diluted earnings per share	$	0.01		$	0.35		$	0.01		$	0.12
Net cash provided by operating activities ⁽²⁾	$	69,051		$	44,974		$	89,230		$	69,424
Net cash used in investing activities ⁽²⁾	$	(697,173	)	$	(208,170	)	$	(215,424	)	$	(227,311	)
Net cash provided by financing activities	$	571,423		$	151,787		$	114,448		$	180,197

(1)	Excludes interest income (expense) net, other income, gain (loss) on commodity price risk management activities net, general and administrative expense and income tax expense (benefit).

(2)

A reclassification was made for the first, second, and third quarters of 2012 to reclassify capitalized interest from operating activities to investing activities in the amounts of $12.5 million, $12.0 million and $11.2 million, respectively. For the quarterly periods ended March 31, 2012, June 30, 2012 and September 30, 2012 filed on Form 10-Q capitalized interest was included in operating activities. The reclassifications increased operating activities and decreased investing activities by the aforementioned amounts for each respective quarter.

WHITING PETROLEUM CORP - FORM 8-K - EX-99.2 - October 6, 2014

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