Chord Energy (WLLBW) 10-K 25 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 16, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	WHITING PETROLEUM CORP
Entity Central Index Key	1,255,474
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		204,385,177
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Entity Public Float			$ 6,876,311,467
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 16,053	$ 78,100
Accounts receivable trade, net	332,428	543,172
Derivative assets	158,729	135,577
Prepaid expenses and other	27,980	86,150
Total current assets	535,190	842,999
Property and equipment:
Oil and gas properties, successful efforts method	13,904,525	14,949,702
Other property and equipment	168,277	276,582
Total property and equipment	14,072,802	15,226,284
Less accumulated depreciation, depletion and amortization	(3,323,102)	(3,083,572)
Total property and equipment, net	$ 10,749,700	12,142,712
Goodwill		875,676
Other long-term assets	$ 104,195	131,724
TOTAL ASSETS	11,389,085	13,993,111
Current liabilities:
Accounts payable trade	77,276	62,664
Accrued capital expenditures	94,105	429,970
Revenues and royalties payable	179,601	254,018
Production Participation Plan liability		113,391
Accrued interest	62,661	67,913
Accrued lease operating expenses	55,291	85,590
Accrued liabilities and other	50,261	80,401
Taxes payable	47,789	63,822
Accrued employee compensation and benefits	32,829	3,202
Total current liabilities	599,813	1,160,971
Long-term debt	5,197,704	5,602,389
Deferred income taxes	593,792	1,278,175
Asset retirement obligations	155,550	167,741
Deferred gain on sale	48,974	60,305
Other long-term liabilities	34,664	20,486
Total liabilities	$ 6,630,497	$ 8,290,067
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 300,000,000 shares authorized; 206,441,303 issued and 204,147,647 outstanding as of December 31, 2015 and 168,346,020 issued and 166,889,152 outstanding as of December 31, 2014	$ 206	$ 168
Additional paid-in capital	4,659,868	3,385,094
Retained earnings	90,530	2,309,712
Total Whiting shareholders' equity	4,750,604	5,694,974
Noncontrolling interest	7,984	8,070
Total equity	4,758,588	5,703,044
TOTAL LIABILITIES AND EQUITY	$ 11,389,085	$ 13,993,111

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
CONSOLIDATED BALANCE SHEETS [Abstract]
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares issued	206,441,303	168,346,020
Common stock, shares outstanding	204,147,647	166,889,152

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES AND OTHER INCOME:
Oil, NGL and natural gas sales	$ 2,092,482	$ 3,024,617	$ 2,666,549
Loss on hedging activities			(1,958)
Gain (loss) on sale of properties	(60,791)	27,657	128,648
Amortization of deferred gain on sale	16,751	30,494	31,737
Interest income and other	2,356	2,329	3,409
Total revenues and other income	2,050,798	3,085,097	2,828,385
COSTS AND EXPENSES:
Lease operating expenses	555,392	496,925	430,221
Production taxes	183,035	253,008	225,403
Depreciation, depletion and amortization	1,243,293	1,089,545	891,516
Exploration and impairment	1,881,671	854,430	453,210
Goodwill impairment	873,772
General and administrative	172,616	177,211	137,994
Interest expense	334,125	170,642	112,936
Loss on early extinguishment of debt	18,361		4,412
Change in Production Participation Plan liability			(6,980)
Commodity derivative (gain) loss, net	(217,972)	(100,579)	7,802
Total costs and expenses	5,044,293	2,941,182	2,256,514
INCOME (LOSS) BEFORE INCOME TAXES	(2,993,495)	143,915	571,871
INCOME TAX EXPENSE (BENEFIT):
Current	(357)	2,625	986
Deferred	(773,870)	76,545	204,882
Total income tax expense (benefit)	(774,227)	79,170	205,868
NET INCOME (LOSS)	(2,219,268)	64,745	366,003
Net loss attributable to noncontrolling interests	86	62	52
NET INCOME (LOSS) AVAILABLE TO SHAREHOLDERS	(2,219,182)	64,807	366,055
Preferred stock dividends			(538)
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS	$ (2,219,182)	$ 64,807	$ 365,517
EARNINGS (LOSS) PER COMMON SHARE:
Basic (in dollars per share)	$ (11.35)	$ 0.53	$ 3.09
Diluted (in dollars per share)	$ (11.35)	$ 0.53	$ 3.06
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic (in shares)	195,472	122,138	118,260
Diluted (in shares)	195,472	122,519	119,588

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
NET INCOME (LOSS)		$ (2,219,268)	$ 64,745	$ 366,003
OTHER COMPREHENSIVE INCOME, NET OF TAX:
OCI amortization on de-designated hedges	[1],[2]			1,236
Total other comprehensive income, net of tax				1,236
COMPREHENSIVE INCOME (LOSS)		(2,219,268)	64,745	367,239
Comprehensive loss attributable to noncontrolling interest		86	62	52
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO WHITING		$ (2,219,182)	$ 64,807	$ 367,291
[1]	Effective April 1, 2009, the Company de-designated all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a result, such mark-to-market values at March 31, 2009 were frozen in accumulated other comprehensive income ("AOCI") as of the de-designation date and were reclassified into earnings as the original hedged transactions affected income. The OCI amortization amount on the de-designated hedges was reclassified from AOCI to loss on hedging activities in the consolidated statements of operations. As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings.
[2]	Presented net of income tax expense of $722 for the year ended December 31, 2013.

CONSOLIDATED STATEMENTS OF COM6

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) $ in Thousands	12 Months Ended
	Dec. 31, 2013USD ($)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
OCI amortization on de-designated hedges, income tax expense	$ 722

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (2,219,268)	$ 64,745	$ 366,003
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	1,243,293	1,089,545	891,516
Deferred income tax expense (benefit)	(773,870)	76,545	204,882
Amortization of debt issuance costs, debt discount and debt premium	46,525	11,984	12,405
Stock-based compensation	28,098	23,258	22,436
Amortization of deferred gain on sale	(16,751)	(30,494)	(31,737)
(Gain) loss on sale of properties	60,791	(27,657)	(128,648)
Undeveloped leasehold and oil and gas property impairments	1,738,308	767,627	358,455
Goodwill impairment	873,772
Exploratory dry hole costs	9,440	26,327	28,725
Loss on early extinguishment of debt	18,361		4,412
Change in Production Participation Plan liability			(6,980)
Non-cash portion of derivative gain	(1,615)	(57,465)	(20,830)
Other, net	(9,337)	(9,030)	(16,118)
Changes in current assets and liabilities:
Accounts receivable trade, net	207,367	17,618	(22,912)
Prepaid expenses and other	54,027	(50,352)	(15,981)
Accounts payable trade and accrued liabilities	(117,136)	(86,480)	33,360
Revenues and royalties payable	(74,417)	(1,963)	48,988
Taxes payable	(16,196)	1,094	16,769
Net cash provided by operating activities	1,051,392	1,815,302	1,744,745
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and development capital expenditures	(2,455,218)	(2,842,837)	(2,349,819)
Acquisition of oil and gas properties	(28,449)	(45,573)	(422,923)
Other property and equipment	(13,266)	(79,955)	(45,304)
Proceeds from sale of oil and gas properties	514,814	107,848	968,606
Issuance of note receivable			(10,530)
Cash paid for investing derivatives			(44,900)
Cash settlements received on investing derivatives			2,371
Net cash used in investing activities	(1,982,119)	(2,860,517)	(1,902,499)
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock	1,111,148
Issuance of 1.25% Convertible Senior Notes due 2020	1,250,000
Redemption of 7% Senior Subordinated Notes due 2014			(253,988)
Borrowings under credit agreement	3,550,000	2,150,000	1,860,000
Repayments of borrowings under credit agreement	(4,150,000)	(1,675,000)	(3,060,000)
Debt and equity issuance costs	(54,461)	(14,901)	(29,690)
Repayment of tax sharing liability		(26,373)	(1,759)
Proceeds from stock options exercised	3,048	1,781
Restricted stock used for tax withholdings	(1,126)	(11,652)	(5,611)
Preferred stock dividends paid			(538)
Net cash provided by financing activities	868,680	423,855	812,414
NET CHANGE IN CASH AND CASH EQUIVALENTS	(62,047)	(621,360)	654,660
CASH AND CASH EQUIVALENTS:
Beginning of period	78,100	699,460	44,800
End of period	16,053	78,100	699,460
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Income taxes paid (refunded), net	(604)	1,380	3,681
Interest paid, net of amounts capitalized	292,852	135,150	66,541
NONCASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures related to property additions	94,105	429,970	158,739
Fair value of equity issued and debt assumed in the Kodiak Acquisition		$ 4,289,088
Senior Notes [Member] | 6.25% Senior Notes due 2023 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of Senior Note	750,000
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of Senior Note			1,204,000
Senior Notes [Member] | 5% Senior Notes due 2019 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of Senior Note			$ 1,100,000
Senior Notes [Member] | 8.125% Senior Notes due 2019 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemption of Senior Notes	(832,429)
Senior Notes [Member] | 5.5% Senior Notes due 2022 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemption of Senior Notes	(404,000)
Senior Notes [Member] | 5.5% Senior Notes due 2021 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemption of Senior Notes	$ (353,500)

CONSOLIDATED STATEMENTS OF CAS8

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Sep. 26, 2013
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes [Member]
Interest Rate (as a percent)	1.25%
6.25% Senior Notes due 2023 [Member] | Senior Notes [Member]
Interest Rate (as a percent)	6.25%
5.75% Senior Notes due 2021 [Member] | Senior Notes [Member]
Interest Rate (as a percent)	5.75%	5.75%	5.75%	5.75%	5.75%
5% Senior Notes due 2019 [Member] | Senior Notes [Member]
Interest Rate (as a percent)	5.00%	5.00%	5.00%	5.00%
8.125% Senior Notes due 2019 [Member] | Senior Notes [Member]
Interest Rate (as a percent)	8.125%	8.125%
5.5% Senior Notes due 2022 [Member] | Senior Notes [Member]
Interest Rate (as a percent)	5.50%
5.5% Senior Notes due 2021 [Member] | Senior Notes [Member]
Interest Rate (as a percent)	5.50%	5.50%
7% Senior Subordinated Notes due 2014 [Member] | Senior Subordinated Notes [Member]
Interest Rate (as a percent)			7.00%

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	Total Whiting Shareholders' Equity [Member]Restricted Stock Units (RSUs) [Member]	Total Whiting Shareholders' Equity [Member]Stock Option [Member]	Total Whiting Shareholders' Equity [Member]Common Stock [Member]	Total Whiting Shareholders' Equity [Member]	Preferred Stock [Member]	Common Stock [Member]Restricted Stock Units (RSUs) [Member]	Common Stock [Member]Common Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]Restricted Stock Units (RSUs) [Member]	Additional Paid-in Capital [Member]Stock Option [Member]	Additional Paid-in Capital [Member]Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Noncontrolling Interest [Member]	Restricted Stock Units (RSUs) [Member]	Stock Option [Member]	Common Stock [Member]	Total
BALANCES at Dec. 31, 2012				$ 3,444,988				$ 119				$ 1,566,717	$ (1,236)	$ 1,879,388	$ 8,184				$ 3,453,172
BALANCES (in shares) at Dec. 31, 2012					172,000			118,582,000
Increase (Decrease) in Shareholders' Equity
Net income (loss)				366,055										366,055	(52)				366,003
Other comprehensive income				1,236									$ 1,236						1,236
Conversion of preferred stock to common				1				$ 1											1
Conversion of preferred stock to common (in shares)					(172,000)			794,000
Restricted stock issued (in shares)								941,000
Restricted stock forfeited (in shares)								(100,000)
Restricted stock used for tax withholdings				(5,611)								(5,611)							(5,611)
Restricted stock used for tax withholdings (in shares)								(115,000)
Stock-based compensation				22,436								22,436							22,436
Preferred dividends paid				(538)										(538)					(538)
BALANCES at Dec. 31, 2013				3,828,567				$ 120				1,583,542		2,244,905	8,132				3,836,699
BALANCES (in shares) at Dec. 31, 2013								120,102,000
Increase (Decrease) in Shareholders' Equity
Net income (loss)				64,807										64,807	(62)				64,745
Issuance of common stock for the Kodiak Acquisition	$ 9,596	$ 7,523	$ 1,771,094				$ 48		$ 9,596	$ 7,523	$ 1,771,046					$ 9,596	$ 7,523	$ 1,771,094
Issuance of common stock for the Kodiak Acquisition (in shares)						258,000	47,546,000
Exercise of stock options				1,781								1,781							1,781
Exercise of stock options (in shares)								117,000									117,123
Restricted stock issued (in shares)								908,000
Restricted stock forfeited (in shares)								(386,000)
Restricted stock used for tax withholdings				(11,652)								(11,652)							(11,652)
Restricted stock used for tax withholdings (in shares)								(199,000)
Stock-based compensation				23,258								23,258							23,258
BALANCES at Dec. 31, 2014				5,694,974				$ 168				3,385,094		2,309,712	8,070				5,703,044
BALANCES (in shares) at Dec. 31, 2014								168,346,000
Increase (Decrease) in Shareholders' Equity
Net income (loss)				(2,219,182)										(2,219,182)	(86)				(2,219,268)
Issuance of common stock				1,100,037				$ 37				1,100,000							1,100,037
Issuance of common stock (in shares)								37,000,000
Equity component of Convertible Senior Notes, net				144,755								144,755							144,755
Exercise of stock options				3,048								3,048							3,048
Exercise of stock options (in shares)								149,000									150,952
Restricted stock issued								$ 1				(1)
Restricted stock issued (in shares)								1,216,000
Restricted stock forfeited (in shares)								(230,000)
Restricted stock used for tax withholdings				(1,126)								(1,126)							(1,126)
Restricted stock used for tax withholdings (in shares)								(40,000)
Stock-based compensation				28,098								28,098							28,098
BALANCES at Dec. 31, 2015				$ 4,750,604				$ 206				$ 4,659,868		$ 90,530	$ 7,984				$ 4,758,588
BALANCES (in shares) at Dec. 31, 2015								206,441,000

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	WHITING PETROLEUM CORPORATION NOTES TO CON SOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Operations —Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company engaged in the development, acquisition, exploration and production of crude oil, NGLs and natural gas primarily in the Rocky Mountains and Permian Basin regions of the United States. Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), Whiting US Holding Company, Whiting Canadian Holding Company ULC (formerly Kodiak Oil & Gas Corp., “Kodiak”), Whiting Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.) and Whiting Programs, Inc. Basis of Presentation of Consolidated Financial Statements —The consolidated financial statements include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s 15.8% ownership interest in Trust I. On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated and such interest in the underlying properties reverted back to Whiting. Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method. Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses. All intercompany balances and transactions have been eliminated upon consolidation. Use of Estimates — The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the 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. Items subject to such estimates and assumptions include (1) oil and natural gas reserves; (2) impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) valuations of our business unit used in impairment tests of goodwill; (7) income taxes; (8) accrued liabilities; (9) valuation of derivative instruments; and (10) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates. Cash and Cash Equivalents —Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less. Accounts Receivable Trade —Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At December 31, 2015 and 2014, the Company had an allowance for doubtful accounts of $12 million and $9 million, respectively. Inventories — Materials and supplies inventories consist primarily of tubular goods and production equipment, carried at weighted-average cost. Materials and supplies are included in other property and equipment. Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or market value and is included in prepaid expenses and other. Oil and Gas Properties Proved. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a unit-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets’ net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. Fair value for oil and gas properties is generally determined based on discounted future net cash flows. Impairment expense for proved properties is reported in exploration and impairment expense. Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings. Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use. During 2015, 2014 and 2013, the Company capitalized interest of $4 million, $4 million and $2 million, respectively. Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on average lease-term lives and the historical experience of developing acreage in a particular prospect. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense for unproved properties is reported in exploration and impairment expense. Exploratory. Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. Cost incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed. Enhanced recovery activities . The Company carries out tertiary recovery methods on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO 2 , for EOR activities that are used during a project’s pilot phase, or prior to a project’s technical and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO 2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO 2 recycling costs are expensed as incurred. Likewise costs incurred to maintain reservoir pressure are also expensed. Other Property and Equipment — Other property and equipment consists of (i) materials and supplies inventories, (ii) leasehold costs and development costs of our CO 2 source properties and (iii) other property and equipment including, furniture and fixtures, buildings, leasehold improvements and automobiles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 4 to 30 years. Goodwill —Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually in the second quarter or whenever events or changes in circumstances indicate that the fair value of the reporting unit may have been reduced below its carrying value. If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings. The Company performed its annual goodwill impairment test as of June 30, 2015, and determined that no impairment had occurred. However, as a result of a sustained decrease in the price of Whiting’s common stock during the third quarter of 2015 caused by a significant decline in crude oil and natural gas prices over that same period, the Company performed another goodwill impairment test as of September 30, 2015. The impairment test performed by the Company indicated that the fair value of its reporting unit was less than its carrying amount, and further that there was no remaining implied fair value attributable to goodwill. Based on these results, the Company recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero . Debt Issuance Costs —Debt issuance costs related to the Company’s senior notes, convertible senior notes and senior subordinated notes are included as a deduction from the carrying amount of long-term debt in the consolidated balance sheets, and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the credit facility are included in other long-term assets, and are amortized to interest expense on a straight-line basis over the term of the agreement. Derivative Instruments —The Company enters into derivative contracts, primarily costless collars and swap contracts, to manage its exposure to commodity price risk. All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria, and the derivative has been designated as a hedge. Effective April 1, 2009, however, the Company elected to discontinue all hedge accounting prospectively, and as of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings. Cash flows from derivatives used to manage commodity price risk are classified in operating activities along with the cash flows of the underlying hedged transactions. The Company does not enter into derivative instruments for speculative or trading purposes. Asset Retirement Obligations and Environmental Costs —Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or when an asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a unit-of-production basis over the proved developed reserves of the related asset. Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability. Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. Deferred Gain on Sale —The deferred gain on sale relates to the sale of 11,677,500 Trust I units and 18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the unit-of-production method. In January 2015, the deferred gain on sale related to Trust I was fully amortized in connection with the termination of the trust’s net profits interest. Revenue Recognition —Oil and gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, persuasive evidence of a sales arrangement exists and collectability of the revenue is reasonably assured. Revenues from the production of gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest (entitlement method). Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as receivables. The Company’s aggregate imbalance positions as of December 31, 2015 and 2014 were not significant. Taxes collected and remitted to governmental agencies on behalf of customers are not included in revenues or costs and expenses. General and Administrative Expenses —General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to the working interest owners that participate in oil and gas properties operated by Whiting. Acquisition Costs — Acquisition related expenses, which consist of external costs directly related to the Company’s acquisitions, such as advisory, legal, accounting, valuation and other professional fees, are expensed as incurred. Maintenance and Repairs —Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred. Major replacements, renewals and betterments are capitalized. Income Taxes —Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense. Earnings Per Share —Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period. Diluted earnings per common share is calculated by dividing adjusted net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards, outstanding stock options and contingently issuable shares of convertible debt, all using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury stock method to the extent that such excess tax benefits are more likely than not to be realized. In addition, to the extent the conversion value of the convertible debt exceeds the aggregate principal amount of the notes, such conversion spread is included in the diluted earnings per share computation under the treasury stock method. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. Industry Segment and Geographic Information —The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers. Concentration of Credit Risk —Whiting is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review. For the year ended December 31, 2015, no individual purchaser accounted for 10% or more of the Company’s total oil, NGL and natural gas sales. The following table presents the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2014 and 2013: 2014 2013 Plains Marketing LP 17% 21% Shell Trading US 10% 14% Bridger Trading LLC 10% 8% Eighty Eight Oil Company 6% 11% Commodity derivative contracts held by the Company are with six counterparties, all of which are participants in Whiting’s credit facility as well, and all of which have investment-grade ratings from Moody’s and Standard & Poor. As of December 31, 2015, outstanding derivative contracts with JP Morgan Chase Bank, N.A. represented 76% of total crude oil volumes hedged. Reclassifications —Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported. Adopted and Recently Issued Accounting Pronouncements — In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014 ‑09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, however, in August 2015, the FASB issued Accounting Standards Update No. 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date (“ASU 2015-14”), which deferred the effective date of ASU 2014 ‑09 for one year. ASU 2015-14 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permit retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application. The Company is currently evaluating the impact of adopting ASU 2014 ‑09 and ASU 2015-14, including the transition method to be applied, however the standards are not expected to have a significant effect on its consolidated financial statements. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016 and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s consolidated financial statements. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”). This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under ASU 2015-15, a Company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, should be applied retrospectively and represent a change in accounting principle. Early adoption is permitted. The Company adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2015, and as a result, $26 million of debt issuance costs related to the Company’s senior notes, convertible senior notes, and senior subordinated notes were reclassified from other long-term assets to long-term debt in the Company’s consolidated balance sheet as of December 31, 2014. The Company elected to continue presenting the debt issuance costs associated with its credit facility as other long-term assets in the consolidated balance sheets. In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”). This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively. Early adoption is permitted. The adoption of this standard will not have a material impact on the Company’s consolidated financial statements. In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). This ASU eliminates the requirement to retrospectively apply measurement-period adjustments made to provisional amounts recognized in a business combination. Under ASU 2015-16, the cumulative impact of a measurement-period adjustment (including the impact on prior periods) should instead be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. This standard should be applied prospectively, and early adoption is permitted. The adoption of this standard is not expected to have a significant impact on the Company’s consolidated financial statements. In November 2015, the FASB issued Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). The objective of this ASU is to simplify the financial statement presentation of deferred taxes by presenting both current and noncurrent deferred tax assets and liabilities as noncurrent on the balance sheet. ASU 2015-17 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. This standard may be applied either prospectively or retrospectively to all periods presented, and early adoption is permitted. The Company adopted ASU 2015-17 as of December 31, 2015 on a retrospective basis, which represents a change in accounting principle. As a result, $48 million of deferred income taxes previously included within current liabilities were reclassified to noncurrent in the Company’s consolidated balance sheet as of December 31, 2014. In January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). This ASU amends the guidance in U.S. GAAP on financial instruments specifically related to (i) the classification and measurement of investments in equity securities, (ii) the presentation of certain fair value changes for financial liabilities measured at fair value and (iii) certain disclosure requirements associated with the fair value of financial instruments. ASU 2016-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted only for the provisions of this ASU related to FASB ASC 825, Financial Instruments . A cumulative-effect adjustment to beginning retained earnings is required as of the beginning of the fiscal year in which this ASU is adopted. The adoption of this standard is not expected to have a significant impact on the Company’s consolidated financial statements.

OIL AND GAS PROPERTIES

OIL AND GAS PROPERTIES	12 Months Ended
	Dec. 31, 2015
OIL AND GAS PROPERTIES [Abstract]
OIL AND GAS PROPERTIES	2. OIL AND GAS PROPERTIES Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2015 and 2014 are as follows (in thousands): December 31, 2015 2014 Proved leasehold costs $ 3,206,237 $ 3,637,026 Unproved leasehold costs 689,754 1,232,040 Costs of completed wells and facilities 9,503,020 9,319,808 Wells and facilities in progress 505,514 760,828 Total oil and gas properties, successful efforts method 13,904,525 14,949,702 Accumulated depletion (3,279,156) (3,003,270) Oil and gas properties, net $ 10,625,369 $ 11,946,432

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2015
ACQUISITIONS AND DIVESTITURES [Abstract]
ACQUISITIONS AND DIVESTITURES	3. ACQUISITIONS AND DIVESTITURES 2015 Acquisitions There were no significant acquisitions during the year ended December 31, 2015. 2015 Divestitures In December 2015, the Company completed the sale of a fresh water delivery system, a produced water gathering system and four saltwater disposal wells located in Weld County, Colorado, effective December 16, 2015, for a purchase price of $75 million (before closing adjustments). In June 2015, the Company completed the sale of its interests in certain non-core oil and gas wells, effective June 1, 2015, for a purchase price of $150 million (before closing adjustments) and resulting in a pre-tax loss on sale of $118 million. The properties included over 2,000 gross wells in 132 fields across 10 states. In April 2015, the Company completed the sale of its interests in certain non-core oil and gas wells, effective May 1, 2015, for a purchase price of $108 million (before closing adjustments) and resulting in a pre-tax gain on sale of $29 million. The properties are located in 187 fields across 14 states, and predominately consist of assets that were previously included in the underlying properties of Whiting USA Trust I. Also during the year ended December 31, 2015, the Company completed several immaterial divestiture transactions for the sale of its interests in certain non-core oil and gas wells and undeveloped acreage, for a total purchase price of $176 million (before closing adjustments) and resulting in a pre-tax gain on sale of $28 million. 2014 Acquisitions On December 8, 2014, the Company completed the acquisition of Kodiak Oil & Gas Corp. (now known as Whiting Canadian Holding Company ULC, “Kodiak”), whereby Whiting acquired all of the outstanding common stock of Kodiak (the “Kodiak Acquisition”). Pursuant to the terms of the Kodiak Acquisition agreement, Kodiak shareholders received 0.177 of a share of Whiting common stock in exchange for each share of Kodiak common stock they owned. Total consideration for the Kodiak Acquisition was $1.8 billion, consisting of 47,546,139 Whiting common shares issued at the market price of $37.25 per share on the date of issuance plus the fair value of Kodiak’s outstanding equity awards assumed by Whiting. The aggregate purchase price of the transaction was $4.3 billion, which included the assumption of Kodiak’s outstanding debt of $2.5 billion as of December 8, 2014 and the net cash acquired of $19 million. Kodiak was an independent energy company focused on exploration and production of crude oil and natural gas reserves, primarily in the Williston Basin region of the United States. As a result of the Kodiak Acquisition, Whiting acquired approximately 327,000 gross ( 178,000 net) acres located primarily in North Dakota, including interests in 778 producing oil and gas wells and undeveloped acreage. Approximately 10,000 of the net acres acquired were located in Wyoming and Colorado. The Kodiak Acquisition was accounted for using the acquisition method of accounting for business combinations. Transaction costs relating to the Kodiak Acquisition were expensed as incurred. The allocation of the purchase price has been finalized, and is based upon management’s estimates and assumptions related to the fair value of assets acquired and liabilities assumed on the acquisition date using currently available information. Since the acquisition date, the Company has recorded adjustments to provisional amounts, and a corresponding decrease to goodwill, totaling $2 million. These adjustments did not have a material impact on the Company’s previously reported consolidated financial statements, and therefore the Company has not retrospectively adjusted those financial statements. The consideration transferred, fair value of assets acquired and liabilities assumed, and the resulting goodwill as of the acquisition date are as follows (in thousands): Consideration: Fair value of Whiting’s common stock issued (1) $ 1,771,094 Fair value of Kodiak restricted stock units assumed by Whiting (2) 9,596 Fair value of Kodiak options assumed by Whiting 7,523 Total consideration $ 1,788,213 Fair value of liabilities assumed: Accounts payable trade $ 18,390 Accrued capital expenditures 97,848 Revenues and royalties payable 57,423 Accrued interest 18,070 Accrued liabilities and other 43,563 Taxes payable 12,807 Long-term debt 2,500,875 Deferred tax liability 31,034 Asset retirement obligations 8,646 Other long-term liabilities 15,735 Amount attributable to liabilities assumed $ 2,804,391 Fair value of assets acquired: Cash and cash equivalents $ 18,879 Accounts receivable trade, net 215,654 Derivative assets 85,718 Prepaid expenses and other 8,523 Oil and gas properties, successful efforts method: Proved properties 2,266,607 Unproved properties 1,000,396 Other property and equipment 11,347 Deferred tax asset 106,758 Other long-term assets 4,950 Amount attributable to assets acquired $ 3,718,832 Goodwill $ 873,772 _____________________ (1) 47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s 268,622,497 common shares outstanding at closing. (2) 257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5 , 2014), based on Kodiak’s 1,455,409 restricted stock units held by employees as of December 8, 2014. Goodwill recognized as a result of the Kodiak Acquisition totaled $874 million, none of which was deductible for income tax purposes. Goodwill was primarily attributable to the operational and financial synergies expected to be realized from the acquisition, including the employment of optimized completion techniques on Kodiak's undrilled acreage which improved hydrocarbon recovery, the realization of savings in drilling and well completion costs, the accelerated development of Kodiak’s asset base, and the acquisition of experienced oil and gas technical personnel. During the third quarter of 2015, the Company determined that the goodwill recognized as a result of the Kodiak Acquisition had become fully impaired and wrote its carrying value down to zero . Refer to the “Fair Value Measurements” footnote for further information regarding goodwill impairment. The changes in the carrying amount of goodwill as of December 31, 2015 and 2014 are as follows (in thousands): Gross Carrying Amount Accumulated Impairment Losses Net Carrying Amount Balance, January 1, 2014 $ - $ - $ - Goodwill acquired 875,676 - 875,676 Balance, December 31, 2014 875,676 - 875,676 Adjustments to previously recorded goodwill (1,904) - (1,904) Impairment losses - (873,772) (873,772) Balance, December 31, 2015 $ 873,772 $ (873,772) $ - The results of operations of Kodiak from the December 8, 2014 closing date through December 31, 2014, representing approximately $46 million of revenue and $17 million of net income, have been included in Whiting’s consolidated statements of operations for the year ended December 31, 2014. 2014 Divestitures In March 2014, the Company completed the sale of approximately 49,900 gross ( 41,000 net) acres in its Big Tex prospect, which consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware Basin of Texas for a cash purchase price of $76 million resulting in a pre-tax gain on sale of $12 million. 2013 Acquisitions In September 2013, the Company completed the acquisition of approximately 39,300 gross ( 17,300 net) acres in the Williston Basin, including interests in 121 producing oil and gas wells and undeveloped acreage, located in Williams and McKenzie counties of North Dakota and Roosevelt and Richland counties of Montana for an initial purchase price of $261 million. Revenue and earnings from these properties since the September 20, 2013 acquisition date are not material, and disclosures of pro forma revenues and net income for this acquisition are also not material and have not been presented accordingly. The acquisition was recorded using the acquisition method of accounting. The initial purchase price has been adjusted for post-closing settlements that have occurred since the acquisition date totaling $6 million. The following table summarizes the allocation of the $256 million adjusted purchase price to the tangible assets acquired and liabilities assumed in this acquisition of oil and gas properties (in thousands): Purchase price $ 255,537 Allocation of purchase price: Oil and gas properties, successful efforts method: Proved properties $ 229,002 Unproved properties 27,335 Oil in tank inventory 522 Accounts receivable 578 Asset retirement obligations (1,900) Total $ 255,537 2013 Divestitures In October 2013, the Company completed the sale of approximately 45,000 gross ( 32,200 net) acres in its Big Tex prospect, which consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware Basin of Texas for a cash purchase price of $15 1 million, resulting in a pre-tax gain on sale of $11 million. Of the total net acres sold, approximately 30,800 net acres are located in Pecos County, Texas, and approximately 1,400 net acres are located in Reeves County, Texas. In July 2013, the Company completed the sale of its interests in certain oil and gas producing properties located in its EOR projects in the Postle and Northeast Hardesty fields in Texas County, Oklahoma, including the related Dry Trail plant gathering and processing facility, oil delivery pipeline, its entire 60% interest in the Transpetco CO 2 pipeline, crude oil swap contracts and certain other related assets and liabilities (collectively the “Postle Properties”) for a cash purchase price of $809 million after selling costs and post-closing adjustments. This divestiture resulted in a pre-tax gain on sale of $109 million. The Company used the net proceeds from this sale to repay a portion of the debt outstanding under its credit agreement. Unaudited Pro Forma Operating Results The following unaudited pro forma combined results of operations for the years ended December 31, 2014 and 2013 are derived from the historical consolidated financial statements of Whiting and Kodiak and give effect to the Kodiak Acquisition as if it had occurred on January 1, 2013. December 31, 2014 2013 (in thousands, except per share data) Total revenues $ 4,141,046 $ 3,774,137 Net income available to common shareholders $ 362,376 $ 576,450 Earnings per common share: Basic $ 2.18 $ 3.48 Diluted $ 2.17 $ 3.46 The unaudited pro forma combined results of operations reflect pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) Whiting common stock and equity awards issued to convert Kodiak’s outstanding shares of common stock and equity awards as of the closing date of the transaction, (ii) adjustments to conform Kodiak’s historical policy of accounting for its oil and natural gas properties from the full cost method to the successful efforts method of accounting, (iii) depletion of Kodiak’s fair-valued proved oil and gas properties, (iv) adjustments to interest expense to reflect the assumption of Kodiak’s debt by Whiting, and (v) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2014 were adjusted to exclude $86 million of acquisition-related costs incurred by Whiting and Kodiak, and the pro forma earnings for the year ended December 31, 2013 were adjusted to include these charges. The unaudited pro forma financial information has been prepared for informational purposes only and does not purport to represent what Whiting’s results of operations would have been had the transactions actually been consummated on the assumed dates nor are they indicative of future results of operations. The unaudited pro forma combined financial information does not reflect future events that may occur after the transactions including, but not limited to, the anticipated realization of ongoing savings from operating efficiencies from the Kodiak Acquisition.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2015
LONG-TERM DEBT [Abstract]
LONG-TERM DEBT	4. LONG-TERM DEBT Long-term debt consisted of the following at December 31, 2015 and 2014 (in thousands): December 31, 2015 2014 Credit agreement $ 800,000 $ 1,400,000 6.5% Senior Subordinated Notes due 2018 350,000 350,000 5% Senior Notes due 2019 1,100,000 1,100,000 8.125% Senior Notes due 2019 - 800,000 1.25% Convertible Senior Notes due 2020 1,250,000 - 5.75% Senior Notes due 2021 1,200,000 1,200,000 5.5% Senior Notes due 2021 - 350,000 5.5% Senior Notes due 2022 - 400,000 6.25% Senior Notes due 2023 750,000 - Total principal 5,450,000 5,600,000 Debt discounts and premiums (203,082) 28,782 Debt issuance costs on notes (49,214) (26,393) Total long-term debt $ 5,197,704 $ 5,602,389 The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of December 31, 2015 (in thousands): 2016 2017 2018 2019 2020 Long-term debt $ - $ - $ 350,000 $ 1,900,000 $ 1,250,000 Credit Agreement —Whiting Oil and Gas, the Company’s wholly-owned subsidiary, has a credit agreement with a syndicate of banks that as of December 31, 2015 had a borrowing base of $4.0 billion, with aggregate commitments of $3.5 billion. The Company may increase the maximum aggregate amount of commitments under the credit agreement up to the $4.0 billion borrowing base if certain conditions are satisfied, including the consent of lenders participating in the increase. As of December 31, 2015, the Company had $2.7 billion of available borrowing capacity, which was net of $800 million in borrowings and $2 million in letters of credit outstanding. In October 2015, the Company entered into an amendment to its existing credit agreement in connection with the November 1, 2015 regular borrowing base redetermination that (i) decreased the borrowing base under the facility from $4.5 billion to $4.0 billion, with no change to the aggregate commitments of $3.5 billion, (ii) extended the Interim Covenant Period (as defined in the credit agreement and below), and (iii) included an additional financial covenant requirement during the Interim Covenant Period. The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of the Company’s proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on May 1 and November 1 of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base. Upon a redetermination of the borrowing base, either on a periodic or special redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, the Company could be forced to immediately repay a portion of its debt outstanding under the credit agreement. A portion of the revolving credit facility in an aggregate amount not to exceed $100 million may be used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company. As of December 31, 2015, $98 million was available for additional letters of credit under the agreement. The credit agreement provides for interest only payments until December 2019, when the credit agreement expires and all outstanding borrowings are due. Interest under the revolving credit facility accrues at the Company’s option at either (i) a base rate for a base rate loan plus the margin in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin in the table below. Additionally, the Company also incurs commitment fees as set forth in the table below on the unused portion of the aggregate commitments of the lenders under the revolving credit facility, which are included as a component of interest expense. At December 31, 2015, the weighted average interest rate on the outstanding principal balance under the credit agreement was 1.9% . Applicable Applicable Margin for Base Margin for Commitment Ratio of Outstanding Borrowings to Borrowing Base Rate Loans Eurodollar Loans Fee Less than 0.25 to 1.0 0.50% 1.50% 0.375% Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 0.75% 1.75% 0.375% Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 1.00% 2.00% 0.50% Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 1.25% 2.25% 0.50% Greater than or equal to 0.90 to 1.0 1.50% 2.50% 0.50% The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders. Except for limited exceptions, the credit agreement also restricts the Company’s ability to make any dividend payments or distributions on its common stock. These restrictions apply to all of the Company’s restricted subsidiaries (as defined in the credit agreement). As of December 31, 2015, there were no retained earnings free from restrictions. The amended credit agreement requires the Company, as of the last day of any quarter, to maintain the following ratios (as defined in the credit agreement): (i) a consolidated current assets to consolidated current liabilities ratio (which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0, (ii) a total senior secured debt to the last four quarters’ EBITDAX ratio of less than 2.5 to 1.0 during the Interim Covenant Period (defined below), and thereafter a total debt to EBITDAX ratio of less than 4.0 to 1.0 and (iii) a ratio of the last four quarters’ EBITDAX to consolidated interest charges of not less than 2.25 to 1.0 during the Interim Covenant Period. Under the amended credit agreement, the “Interim Covenant Period” is defined as the period from June 30, 2015 until the earlier of (a) April 1, 2018 or (b) the commencement of an investment-grade debt rating period as described below. The Company was in compliance with its covenants under the credit agreement as of December 31, 2015. Under the terms of the credit agreement, at any time during which Whiting has an investment-grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Group and Whiting has elected, at its discretion, to effect an investment-grade rating period, (i) certain security requirements, including the borrowing base requirement, and restrictive covenants will cease to apply, (ii) certain other restrictive covenants will become less restrictive, (iii) an additional financial covenant will be imposed, and (iv) the interest rate margin applicable to all revolving borrowings as well as the commitment fee with respect to the revolving facility will be based upon the Company’s debt rating rather than the ratio of outstanding borrowings to the borrowing base. The obligations of Whiting Oil and Gas under the credit agreement are secured by a first lien on substantially all of Whiting Oil and Gas’ and Whiting Resource Corporation’s properties included in the borrowing base for the credit agreement. The Company has guaranteed the obligations of Whiting Oil and Gas under the credit agreement and has pledged the stock of its subsidiaries as security for its guarantee. Senior Notes and Senior Subordinated Notes —In September 2010, the Company issued at par $350 million of 6.5% Senior Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”). The estimated fair value of these notes was $ 265 million and $345 million as of December 31, 2015 and 2014, respectively, based on quoted market prices for this debt security, and such fair value is therefore designated as Level 1 within the valuation hierarchy. In September 2013, the Company issued at par $1.1 billion of 5% Senior Notes due March 2019 (the “2019 Senior Notes”) and $800 million of 5.75% Senior Notes due March 2021, and issued at 101% of par an additional $400 million of 5.75% Senior Notes due March 2021 (collectively, the “2021 Senior Notes”). The $4 million debt premium recorded in connection with the issuance of the 2021 Senior Notes is amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 5.5% per annum. The estimated fair value of the 2019 Senior Notes was $ 831 million and $1 .0 billion as of December 31, 2015 and 2014, respectively. The estimated fair value of the 2021 Senior Notes was $8 70 million and $1 .1 billion as of December 31, 2015 and 2014, respectively. These fair values are based on quoted market prices for these debt securities, and such fair values are therefore designated as Level 1 within the valuation hierarchy. Issuance of Senior Notes. In March 2015, the Company issued at par $750 million of 6.25% Senior Notes due April 2023 (the “2023 Senior Notes” and together with the 2019 Senior Notes and 2021 Senior Notes, the “Whiting Senior Notes”). The Company used the net proceeds from this issuance to repay a portion of the debt outstanding under its credit agreement. The estimated fair value of the 2023 Senior Notes was $544 million as of December 31, 2015. The fair value is based on quoted market prices for this debt security, and such fair value is therefore designated as Level 1 within the valuation hierarchy. Redemption of Senior Subordinated Notes. In October 2013, the Company paid $254 million to redeem its entire $250 million aggregate principal amount of the 7% Senior Subordinated Notes due February 2014 (the “2014 Senior Subordinated Notes”) at a redemption price of 101.595% . Concurrent with this redemption, the Company paid all accrued and unpaid interest on the 2014 Senior Subordinated Notes up to but not including the redemption date. The Company financed the redemption of these notes with proceeds from the issuance of the Whiting Senior Notes, as discussed above. As a result of the redemption, Whiting recognized a $4 million loss on early extinguishment of debt, which primarily consisted of a cash charge of $4 million related to the redemption premium on the 2014 Senior Subordinated Notes. Kodiak Senior Notes. In conjunction with the Kodiak Acquisition, Whiting US Holding Company, a wholly-owned subsidiary of the Company, became a co-issuer of Kodiak’s $800 million of 8.125% Senior Notes due December 2019 (the “2019 Kodiak Notes”) , $350 million of 5.5% Senior Notes due January 2021 (the “2021 Kodiak Notes”) , and $400 million of 5.5% Senior Notes due February 2022 ( the “2022 Kodiak Notes” and together with the 2019 Kodiak Notes and the 2021 Kodiak Notes, the “Kodiak Notes”). The Kodiak Notes were recorded at their fair values of $824 million, $351 million and $401 million, respectively, on December 8, 2014, the closing date of the acquisition. Upon closing of the Kodiak Acquisition, the indentures under which the Kodiak Notes were issued (the “Kodiak Indentures”) were amended to (i) modify certain covenants and restrictions, (ii) provide for unconditional and irrevocable guarantees by Whiting Petroleum Corporation and Whiting Oil and Gas of the prompt payment, when due, of any amounts owed under the Kodiak Notes and the Kodiak Indentures, and (iii) allow Whiting US Holding Company to become a co-issuer of the Kodiak Notes. Also in conjunction with the Kodiak Acquisition, in December 2014, each of the indentures governing the Company’s 2019 Senior Notes, 2021 Senior Notes and 2018 Senior Subordinated Notes were amended to include Whiting US Holding Company, Kodiak and Whiting Resources Corporation as guarantors. Shortly after closing, the Kodiak Notes were deregistered in accordance with the Securities Exchange Act of 1934, and accordingly, the Company is exempt from the reporting requirements under Rule 3-10 of Regulation S-X of the SEC with respect to the Kodiak Notes. Repurchase of Kodiak Notes. On January 7, 2015, as required under the Kodiak Indentures upon a change in control of Kodiak, Whiting offered to repurchase at 101% of par all $1,550 million principal amount of Kodiak Notes then outstanding. On March 6, 2015, Whiting paid $760 million to repurchase $2 million aggregate principal amount of the 2019 Kodiak Notes, $346 million aggregate principal amount of the 2021 Kodiak Notes and $399 million aggregate principal amount of the 2022 Kodiak Notes, which payment consisted of the 101% redemption price and all accrued and unpaid interest on such notes. On May 1, 2015, Whiting paid $5 million to repurchase the remaining $4 million aggregate principal amount of the 2021 Kodiak Notes and $1 million aggregate principal amount of the 2022 Kodiak Notes, which payment consisted of the 101% redemption price and all accrued and unpaid interest on such notes. The Company financed the repurchases with borrowings under its revolving credit facility, which borrowings were subsequently repaid with proceeds from the equity offerings discussed within the “Shareholders’ Equity and Noncontrolling Interest” footnote and the debt offerings discussed within this footnote, and with cash on hand. On December 24, 2015, Whiting paid $834 million to repurchase the remaining $798 million aggregate principal amount of the 2019 Kodiak Notes, which payment consisted of the 104.063% redemption price and all accrued and unpaid interest on such notes. The Company financed the December note repurchase with borrowings under its credit agreement. As a result of the repurchases, Whiting recognized an $18 million loss on early extinguishment of debt, which consisted of a $40 million cash charge related to the redemption premium on the Kodiak Notes, partially offset by a $22 million non-cash credit related to the acceleration of unamortized debt premiums on such notes. The estimated fair value of the 2019, 2021 and 2022 Kodiak Notes at December 31, 2014 was $812 million, $351 million and $401 million, respectively, based on quoted market prices for these debt securities, and such fair value wa s therefore designated as Level 1 within the valuation hierarchy. Convertible Senior Notes —In March 2015, the Company issued at par $1,250 million of 1.25% Convertible Senior Notes due April 2020 (the “Convertible Senior Notes”) for net proceeds of $1.2 billion, net of initial purchasers’ fees of $25 million. The Company used the net proceeds from this issuance to repay a portion of the debt outstanding under its credit agreement. The notes will mature on April 1, 2020 unless earlier converted in accordance with their terms. The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Convertible Senior Notes in cash upon conversion. Prior to January 1, 2020, the Convertible Senior Notes will be convertible only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on June 30, 2015 (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of the Convertible Senior Notes for each trading day of the measurement period is less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after January 1, 2020, the Convertible Senior Notes will be convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the notes. The notes will be convertible at an initial conversion rate of 25.6410 shares of Whiting’s common stock per $1,000 principal amount of the notes, which is equivalent to an initial conversion price of approximately $39.00 . The conversion rate will be subject to adjustment in some events. In addition, following certain corporate events that occur prior to the maturity date, the Company will increase, in certain circumstances, the conversion rate for a holder who elects to convert its Convertible Senior Notes in connection with such corporate event. As of December 31, 2015, none of the contingent conditions allowing holders of the Convertible Senior Notes to convert these notes had been met. Upon issuance, the Company separately accounted for the liability and equity components of the Convertible Senior Notes. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the Convertible Senior Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of 5.6% per annum. The fair value of the Convertible Senior Notes as of the issuance date was estimated at $1.0 billion, resulting in a debt discount at inception of $238 million. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the Convertible Senior Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital within shareholders’ equity, and will not be remeasured as long as it continues to meet the conditions for equity classification. Transaction costs related to the Convertible Senior Notes issuance were allocated to the liability and equity components based on their relative fair values. Issuance costs attributable to the liability component were recorded as a reduction to the carrying value of long-term debt on the consolidated balance sheet and are being amortized to expense over the term of the notes using the effective interest method. Issuance costs attributable to the equity component were recorded as a charge to additional paid-in capital within shareholders’ equity. The Convertible Senior Notes consist of the following at December 31, 2015 (in thousands): Liability component: Principal $ 1,250,000 Less: note discount (205,572) Net carrying value $ 1,044,428 Equity component (1) $ 237,500 (1) Recorded in additional paid-in capital, net of $5 million of issuance costs and $88 million of deferred taxes. The estimated fair value of the Convertible Senior Notes was $850 million as of December 31, 2015. The fair value is based on quoted market prices for this debt security, and such fair value is therefore designated as Level 1 within the valuation hierarchy. Interest expense recognized on the Convertible Senior Notes related to the stated interest rate and amortization of the debt discount totaled $44 million for the year ended December 31, 2015. The Whiting Senior Notes and the Convertible Senior Notes are unsecured obligations of Whiting Petroleum Corporation and these unsecured obligations are subordinated to all of the Company’s secured indebtedness, which consists of Whiting Oil and Gas’ credit agreement. The 2018 Senior Subordinated Notes are also unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the Company’s senior debt, which currently consists of the Whiting Senior Notes, the Convertible Senior Notes and borrowings under Whiting Oil and Gas’ credit agreement. The Company’s obligations under the 2018 Senior Subordinated Notes, the Whiting Senior Notes and the Convertible Senior Notes are guaranteed by the Company’s wholly-owned subsidiaries, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian Holding Company ULC and Whiting Resources Corporation (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. Any subsidiaries other than these Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S ‑X of the SEC. Whiting Petroleum Corporation has no assets or operations independent of this debt and its investments in its consolidated subsidiaries.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2015
ASSET RETIREMENT OBLIGATIONS [Abstract]
ASSET RETIREMENT OBLIGATIONS	5. ASSET RETIREMENT OBLIGATIONS The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration (including removal of certain onshore and offshore facilities in California) in accordance with applicable local, state and federal laws. The Company follows FASB ASC Topic 410, Asset Retirement and Environmental Obligations , to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations. The current portions at December 31, 2015 and 2014 were $6 million and $12 million, respectively, and have been included in accrued liabilities and other. Revisions to the liability typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2015 and 2014 (in thousands): December 31, 2015 2014 Asset retirement obligation at January 1 $ 179,931 $ 126,148 Additional liability incurred 9,208 29,186 Revisions to estimated cash flows (1) 29,307 25,909 Accretion expense 20,274 13,548 Obligations on sold properties (69,601) (7,237) Liabilities settled (7,211) (7,623) Asset retirement obligation at December 31 $ 161,908 $ 179,931 (1) Revisions in estimated cash flows during the years ended December 31, 2015 and 2014 are primarily attributable to increased estimates of future costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains and Permian Basin regions.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2015
DERIVATIVE FINANCIAL INSTRUMENTS [Abstract]
DERIVATIVE FINANCIAL INSTRUMENTS	6. DERIVATIVE FINANCIAL INSTRUMENTS The Company is exposed to certain risks relating to its ongoing business operations, and Whiting uses derivative instruments to manage its commodity price risk. Whiting follows FASB ASC Topic 815, Derivatives and Hedging , to account for its derivative financial instruments. Commodity Derivative Contracts — Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. Whiting enters into derivative contracts, such as costless collars, swaps and crude oil sales and delivery contracts, to achieve a more predictable cash flow by reducing its exposure to commodity price volatility. Commodity derivative contracts are thereby used to ensure adequate cash flow to fund the Company’s capital programs and to manage returns on drilling programs and acquisitions. The Company does not enter into derivative contracts for speculative or trading purposes. Crude Oil Costless Collars. Costless collars are designed to establish floor and ceiling prices on anticipated future oil or gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The table below details the Company’s costless collar derivatives entered into to hedge forecasted crude oil production revenues as of January 1, 2016. Whiting Petroleum Corporation Derivative Contracted Crude Weighted Average NYMEX Price Instrument Period Oil Volumes (Bbl) Collar Ranges for Crude Oil (per Bbl) Three-way collars (1) Jan - Dec 2016 16,800,000 $43.75 - $53.75 - $74.40 Collars Jan - Dec 2016 3,000,000 $51.00 - $63.48 Jan - Dec 2017 3,000,000 $53.00 - $70.44 Total 22,800,000 _____________________ (1) A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price. In March 2013, Whiting entered into certain crude oil swap contracts in order to achieve more predictable cash flows and manage returns on certain oil and gas properties that the Company was considering for monetization. Accordingly, the acquisition of these swap contracts and cash receipts from settlements of these swap positions have been reflected as an investing activity in the statement of cash flows. On July 15, 2013, upon closing of the sale of the Postle Properties discussed in the “Acquisitions and Divestitures” footnote, these crude oil swaps were novated to the buyer. Cash settlements that do not relate to investing derivatives or that do not have a significant financing element are reflected as operating activities in the statement of cash flows. Crude Oil Sales and Delivery Contract. The Company has a long-term crude oil sales and delivery contract for oil volumes produced from its Redtail field in Colorado. Under the terms of the agreement, Whiting has committed to deliver certain fixed volumes of crude oil through 2020. The Company determined that it was not probable that future oil production from its Redtail field would be sufficient to meet the minimum volume requirement specified in this contract, and accordingly, that the Company would not settle this contract through physical delivery of crude oil volumes. As a result, Whiting determined that this contract would not qualify for the “normal purchase normal sale” exclusion and has therefore reflected the contract at fair value in the consolidated financial statements. As of December 31, 2015, the estimated fair value of this derivative contract was a liability of $ 4 million. Embedded Commodity Derivative Contract — In May 2011, Whiting entered into a long-term contract to purchase CO 2 for use in its EOR project that is being carried out at its North Ward Estes field in Texas. This contract contained a price adjustment clause that was linked to changes in NYMEX crude oil prices. The Company had determined that the portion of this contract linked to NYMEX oil prices was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded pricing feature from its host contract and reflected it at fair value in the consolidated financial statements. This contract has been terminated, however, and the fair value of this embedded derivative is therefore zero . Derivative Instrument Reporting — All derivative instruments are recorded in the consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion. The following tables summarize the effects of commodity derivative instruments on the consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 (in thousands): Loss Reclassified from AOCI into Income (Effective Portion) ASC 815 Cash Flow Statement of Operations Year Ended December 31, Hedging Relationships (1) Classification 2015 2014 2013 Commodity contracts Loss on hedging activities $ - $ - $ (1,958) ____________________ (1) Effective April 1, 2009, the Company de-designated all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions affected income. As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings. (Gain) Loss Recognized in Income Not Designated as Statement of Operations Year Ended December 31, ASC 815 Hedges Classification 2015 2014 2013 Commodity contracts Commodity derivative (gain) loss, net $ (217,972) $ (136,995) $ 20,503 Embedded commodity contracts Commodity derivative (gain) loss, net - 36,416 (12,701) Total $ (217,972) $ (100,579) $ 7,802 Offsetting of Derivative Assets and Liabilities. The Company typically has numerous hedge positions with each individual financial derivative counterparty that span a several-month time period and that typically result in both fair value asset and liability positions held with that counterparty. These positions are all offset to a single fair value asset or liability amount at the end of each reporting period. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The following tables summarize the location and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands): December 31, 2015 (1) Net Gross Recognized Recognized Gross Fair Value Not Designated as Assets/ Amounts Assets/ ASC 815 Hedges Balance Sheet Classification Liabilities Offset Liabilities Derivative assets: Commodity contracts - current Derivative assets $ 258,778 $ (100,049) $ 158,729 Commodity contracts - non-current Other long-term assets 31,415 (3,465) 27,950 Total derivative assets $ 290,193 $ (103,514) $ 186,679 Derivative liabilities: Commodity contracts - current Accrued liabilities and other $ 101,214 $ (100,049) $ 1,165 Commodity contracts - non-current Other long-term liabilities 6,327 (3,465) 2,862 Total derivative liabilities $ 107,541 $ (103,514) $ 4,027 December 31, 2014 (1) Net Gross Recognized Recognized Gross Fair Value Not Designated as Assets/ Amounts Assets/ ASC 815 Hedges Balance Sheet Classification Liabilities Offset Liabilities Derivative assets: Commodity contracts - current Derivative assets $ 154,329 $ (18,752) $ 135,577 Commodity contracts - non-current Other long-term assets 45,459 - 45,459 Total derivative assets $ 199,788 $ (18,752) $ 181,036 Derivative liabilities: Commodity contracts - current Accrued liabilities and other $ 18,752 $ (18,752) $ - Total derivative liabilities $ 18,752 $ (18,752) $ - _____________________ (1) Because counterparties to the Company’s financial derivative contracts are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above. Contingent Features in Financial Derivative Instruments . None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are lenders under Whiting’s credit agreement. The Company uses only credit agreement participants to hedge with, since these institutions are secured equally with the holders of Whiting’s bank debt, which eliminates the potential need to post collateral when Whiting is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2015
FAIR VALUE MEASUREMENTS [Abstract]
FAIR VALUE MEASUREMENTS	7. FAIR VALUE MEASUREMENTS Cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates. The Company’s senior notes, convertible senior notes and senior subordinated notes are recorded at cost, and the fair values of these instruments are included in the “Long-Term Debt” footnote. The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparties, as appropriate. The Company follows FASB ASC Topic 820, Fair Value Measurement and Disclosure , which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: · Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. · Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. · Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement. A financial instrument’s categorization within the valuation hierarchy is based upon 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 in its entirety requires judgment and considers factors specific to the asset or liability. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. The following tables present information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2015 and 2014, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands): Total Fair Value Level 1 Level 2 Level 3 December 31, 2015 Financial Assets Commodity derivatives – current $ - $ 158,729 $ - $ 158,729 Commodity derivatives – non-current - 27,950 - 27,950 Total financial assets $ - $ 186,679 $ - $ 186,679 Financial Liabilities Commodity derivatives – current $ - $ - $ 1,165 $ 1,165 Commodity derivatives – non-current - - 2,862 2,862 Total financial liabilities $ - $ - $ 4,027 $ 4,027 Total Fair Value Level 1 Level 2 Level 3 December 31, 2014 Financial Assets Commodity derivatives – current $ - $ 127,506 $ 8,071 $ 135,577 Commodity derivatives – non-current - - 45,459 45,459 Total financial assets $ - $ 127,506 $ 53,530 $ 181,036 The following methods and assumptions were used to estimate the fair values of the Company’s financial assets and liabilities that are measured on a recurring basis: Commodity Derivatives . Commodity derivative instruments consist mainly of costless collars and swap contracts for crude oil. The Company’s costless collars and swaps are valued based on an income approach. Both the option and swap models consider various assumptions, such as quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations. In addition, the Company has a long-term crude oil sales and delivery contract, whereby it has committed to deliver certain fixed volumes of crude oil through 2020. Whiting has determined that the contract did not meet the “normal purchase normal sale” exclusion, and has therefore reflected this contract at fair value in its consolidated financial statements. This commodity derivative was valued based on an income approach, which considers various assumptions, including quoted forward prices for commodities, market differentials for crude oil, U.S. Treasury rates and either the Company’s or the counterparty’s nonperformance risk, as appropriate. The assumptions used in the valuation of the crude oil sales and delivery contract include certain market differential metrics that were unobservable during the term of the contract. Such unobservable inputs were significant to the contract valuation methodology, and the contract’s fair value was therefore designated as Level 3 within the valuation hierarchy. Level 3 Fair Value Measurements. A third-party valuation specialist is utilized to determine the fair value of the commodity derivative instruments designated as Level 3. The Company reviews these valuations (including the related model inputs and assumptions) and analyzes changes in fair value measurements between periods. The Company corroborates such inputs, calculations and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information from other published sources. T he following table presents a reconciliation of changes in the fair value of financial assets or liabilities designated as Level 3 in the valuation hierarchy for the years ended December 31, 2015 and 2014 (in thousands): Year Ended December 31, 2015 2014 Fair value asset, beginning of period $ 53,530 $ 36,416 Unrealized gains (losses) on commodity derivative contracts included in earnings (1) (24,018) 17,114 Commodity derivative contract settlements (33,539) - Transfers into (out of) Level 3 - - Fair value asset (liability), end of period $ (4,027) $ 53,530 _____________________ (1) Included in commodity derivative (gain) loss, net in the consolidated statements of operations. Quantitative Information About Level 3 Fair Value Measurements. The significant unobservable inputs used in the fair value measurement of the Company’s commodity derivative contract designated as Level 3 are as follows: Fair Value at December 31, 2015 Valuation Unobservable Amount (in thousands) Technique Input (per Bbl) Commodity derivative contract ($4,027) Income approach Market differential for crude oil $5.25 Sensitivity to Changes In Significant Unobservable Inputs. As presented above, the significant unobservable inputs used in the fair value measurement of Whiting’s commodity derivative contract are the market differentials for crude oil over the term of the contract. Significant increases or decreases in these unobservable inputs in isolation would result in a significantly higher or lower, respectively, fair value liability measurement. Non-recurring Fair Value Measurements . The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property and goodwill. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The following tables present information about the Company’s non-financial assets measured at fair value on a non-recurring basis during the years ended December 31, 2015 and 2014, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands): Loss (Before Net Carrying Tax) Year Value as of Ended September 30, Fair Value Measurements Using December 31, 2015 Level 1 Level 2 Level 3 2015 Proved property (1) $ 531,775 $ - $ - $ 531,775 $ 1,602,226 Goodwill (2) - - - - 873,772 Total non-recurring assets at fair value $ 531,775 $ - $ - $ 531,775 $ 2,475,998 _____________________ (1) During the third quarter of 2015, proved oil and gas properties with a previous carrying amount of $2.1 billion were written down to their fair value as of September 30, 2015 of $531 million, resulting in a non-cash impairment charge of $1.5 billion which was recorded within exploration and impairment expense. The impaired properties consisted of the Company’s North Ward Estes field in Texas and other non-core proved oil and gas properties primarily in Texas, Wyoming, North Dakota and Colorado that are not currently being developed due to depressed oil and gas prices. Also during the third quarter of 2015, proved CO 2 properties at the Bravo Dome field in New Mexico and the McElmo Dome field in Colorado with a previous carrying amount of $63 million were written down to their fair value as of September 30, 2015 of $1 million, resulting in a non-cash impairment charge of $62 million which was also recorded within exploration and impairment expense. (2) During 2015, goodwill related to the Kodiak Acquisition with a carrying amount of $874 million was written down to its fair value of zero , resulting in a non-cash impairment charge of $874 million which was recorded as a separate line in the consolidated statements of operations. Loss (Before Net Carrying Tax) Year Value as of Ended December 31, Fair Value Measurements Using December 31, 2014 Level 1 Level 2 Level 3 2014 Proved property (1) $ 179,155 $ - $ - $ 179,155 $ 629,450 _____________________ (1) During the fourth quarter of 2014, proved oil and gas properties with a previous carrying amount of $763 million were written down to their fair value as of December 31, 2014 of $176 million, resulting in a non-cash impairment charge of $587 million which was recorded within exploration and impairment expense. The impaired properties consisted of non-core proved oil and gas properties primarily in Colorado, Louisiana, North Dakota and Utah that were not being developed due to depressed oil and gas prices as of December 31, 2014. Also during the fourth quarter of 2014, proved CO 2 properties at the Bravo Dome field in New Mexico with a previous carrying amount of $45 million were written down to their fair value as of December 31, 2014 of $3 million, resulting in a non-cash impairment charge of $42 million which was also recorded within exploration and impairment expense. The following methods and assumptions were used to estimate the fair values of the non-financial assets in the tables above: Proved Property Impairments . The Company tests proved property for impairment whenever events or changes in circumstances indicate that the fair value of these assets may be reduced below their carrying value. As a result of the significant decrease in the forward price curves for crude oil and natural gas during the third quarter of 2015 and during the fourth quarter of 2014, and the associated decline in oil and gas reserves over those same periods, the Company performed proved property impairment tests as of September 30, 2015 and December 31, 2014, respectively. The fair value was ascribed using income approach analyses based on the net discounted future cash flows from the producing property and a market approach analysis, which approaches have been probability-weighted. The discounted cash flows are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and gas or CO 2 production, as the case may be, from the Company’s reserve reports, commodity prices based on sales contract terms or forward price curves (adjusted for basis differentials), operating and development costs, and a discount rate based on the Company’s weighted-average cost of capital (all of which are designated as Level 3 inputs within the fair value hierarchy). The impairment tests indicated that a proved property impairment had occurred, and the Company therefore recorded a non-cash impairment charge to reduce the carrying value of the impaired property to its fair value at the measurement date. Goodwill Impairment. The Company tests goodwill for impairment annually in the second quarter or whenever events or changes in circumstances indicate that the fair value of its reporting unit may have been reduced below its carrying value. The Company performed its annual goodwill impairment test as of June 30, 2015, and determined that no impairment had occurred. However, as a result of a sustained decrease in the price of Whiting’s common stock during the third quarter of 2015 caused by a significant decline in crude oil and natural gas prices over that same period, the Company performed another goodwill impairment test as of September 30, 2015. The fair value of the Company’s reporting unit was ascribed using an income approach analysis based on the Company’s net discounted future cash flows and a market approach analysis. The discounted cash flows are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on sales contract terms or forward price curves (adjusted for basis differentials), operating and development costs, and a discount rate based on the Company’s weighted-average cost of capital (all of which are designated as Level 3 inputs within the fair value hierarchy). The impairment test performed by the Company indicated that the fair value of its reporting unit was less than its carrying amount, and further that there was no remaining implied fair value attributable to goodwill. Based on these results, the Company recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero .

DEFERRED COMPENSATION

DEFERRED COMPENSATION	12 Months Ended
	Dec. 31, 2015
DEFERRED COMPENSATION [Abstract]
DEFERRED COMPENSATION	8. DEFERRED COMPENSATION Production Participation Plan —The Company had a Production Participation Plan (the “Plan”) in which all employees participated. On June 11, 2014, the Board of Directors of the Company terminated the Plan effective December 31, 2013. Prior to Plan termination, interests in oil and gas properties acquired, developed or sold during the year were allocated to the Plan on an annual basis as determined by the Compensation Committee of the Company’s Board of Directors. Once allocated, the interests (not legally conveyed) were fixed. Interest allocations prior to 1995 consisted of 2% ‑ 3% overriding royalty interests. Interest allocations after 1995 were 1.75% ‑ 5% of oil and gas sales less lease operating expenses and production taxes. Employees vested in the Plan ratably at 20% per year over a five -year period. However, pursuant to the terms of the Plan, upon Plan termination all employees fully vested, and the Company was required to distribute to each Plan participant an amount, based upon the valuation method set forth in the Plan, in a lump sum payment twelve months after the date of termination. This distribution included the value of proved undeveloped oil and gas properties awarded upon Plan termination and was based on forecasted commodity prices for crude oil, NGLs and natural gas as of December 31, 2013. The fully vested amount due to Plan participants totaling $113 million was reflected as a current payable as of December 31, 2014, and was paid to Plan participants in 2015. Accrued compensation expense under the Plan for the year ended December 31, 2014 primarily related to the change in liability for employee vestings and PUDs assigned upon Plan termination and amounted to $24 million charged to general and administrative expense and $2 million charged to exploration expense. Prior to Plan termination, the Company recorded non-cash changes in the present value of estimated future payments under the Plan as a separate line item in the consolidated statements of operations. 401(k) Plan —The Company has a defined contribution retirement plan for all employees. The plan is funded by employee contributions and discretionary Company contributions. The Company’s contributions for 2015, 2014 and 2013 were $12 million, $9 million and $8 million, respectively. Employees vest in employer contributions at 20% per year of completed service.

SHAREHOLDERS' EQUITY AND NONCON

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST	12 Months Ended
	Dec. 31, 2015
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST [Abstract]
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST	9. SHAREHOLDERS ’ EQUITY AND NONCONTROLLING INTEREST 6.25% Convertible Perpetual Preferred Stock —In June 2009, the Company completed a public offering of 6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a price of $100.00 per share. As a result of voluntary conversions and the Company exercising its right to mandatorily convert shares of preferred stock effective June 27, 2013, all 172,129 remaining shares of preferred stock outstanding on March 31, 2013 were converted into 792,919 shares of common stock. As of December 31, 2015 and 2014, no shares of preferred stock remain issued or outstanding . Each holder of the preferred stock was entitled to an annual dividend of $6.25 per share to be paid quarterly in cash, common stock or a combination thereof on March 15, June 15, September 15 and December 15, once such dividend had been declared by Whiting’s board of directors. Common Stock Offering — In March 2015, the Company completed a public offering of its common stock, selling 35,000,000 shares of common stock at a price of $30.00 per share and providing net proceeds of approximately $1.0 billion after underwriter’s fees. In addition, the Company granted the underwriter a 30 -day option to purchase up to an additional 5,250,000 shares of common stock. On April 1, 2015, the underwriter exercised its right to purchase an additional 2,000,000 shares of common stock, providing additional net proceeds of $61 million. The Company used the net proceeds from these offerings to repay a portion of the debt outstanding under its credit agreement, as well as for general corporate purposes. Equity Incentive Plan —At the Company’s 2013 Annual Meeting held on May 7, 2013, shareholders approved the Whiting Petroleum Corporation 2013 Equity Incentive Plan (the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and includes the authority to issue 5,300,000 shares of the Company’s common stock. Upon shareholder approval of the 2013 Equity Plan, the 2003 Equity Plan was terminated. The 2003 Equity Plan continues to govern awards that were outstanding as of the date of its termination, which remain in effect pursuant to their terms. Any shares netted or forfeited after May 7, 2013 under the 2003 Equity Plan and any shares forfeited under the 2013 Equity Plan will be available for future issuance under the 2013 Equity Plan. However, shares netted for tax withholding under the 2013 Equity Plan will be cancelled and will not be available for future issuance. Under the 2013 Equity Plan, no employee or officer participant may be granted options for more than 600,000 shares of common stock, stock appreciation rights relating to more than 600,000 shares of common stock, or more than 300,000 shares of restricted stock during any calendar year. On December 8, 2014, the Company increased the number of shares issuable under the 2013 Equity Plan by 978,161 shares to accommodate for the conversion of Kodiak’s outstanding equity awards to Whiting equity awards upon closing of the Kodiak Acquisition. Any shares netted or forfeited under this increased availability will be cancelled and will not be available for future issuance under the 2013 Equity Plan. As of December 31, 2015, 4,108,863 shares of common stock remained available for grant under the 2013 Equity Plan. For the years ended December 31, 2015, 2014 and 2013, total stock compensation expense recognized for restricted share awards and stock options was $28 million, $23 million and $22 million, respectively. Equity Awards Assumed in Kodiak Acquisition. Upon closing of the Kodiak Acquisition, the Company assumed all of Kodiak’s outstanding equity awards, including restricted stock awards, restricted stock units and stock options. Kodiak’s outstanding equity awards held by employees were converted into Whiting’s equity awards using a conversion ratio of 0.177 . The outstanding restricted stock awards and restricted stock units vested upon closing of the transaction, and the $10 million estimated fair value as of the closing date of the 257,601 shares of Whiting common stock issued to convert these awards was recorded as part of the purchase consideration. The estimated fair value as of the closing date of the 673,235 Whiting options issued in exchange for Kodiak’s outstanding options was approximately $8 million, based on a Black-Scholes option-pricing model. Of this value, approximately $7 million was attributable to service rendered prior to the date of acquisition and was recorded as part of the purchase consideration, and the remaining $1 million will be expensed over the remaining service term of the replacement stock option awards. The unvested stock option awards will vest over a one to three -year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date. The following table summarizes the assumptions used to estimate the fair value of stock options assumed in the Kodiak Acquisition: 2014 Risk-free interest rate 0.08% - 1.90% Expected volatility 40.3% - 49.7% Expected term 2.0 yrs. - 6.1 yrs. Dividend yield - The weighted average fair value of these options, as determined by the Black-Scholes valuation model, was $12.20 per share as of the December 8, 2014 closing date of the Kodiak Acquisition. Restricted Shares . The Company grants service-based restricted stock awards to executive officers and employees, which generally vest ratably over a three -year service period, and to directors, which generally vest over a one -year service period. In addition, the Company grants restricted stock awards to executive officers that are subject to market-based vesting criteria as well as a three-year service period. The Company uses historical data and projections to estimate expected employee behaviors related to restricted stock forfeitures. The expected forfeitures are then included as part of the grant date estimate of compensation cost. The Company recognizes compensation expense for all awards subject to market conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense is not reversed if vesting does not actually occur. In January 2015, 391,773 shares of restricted stock subject to certain market-based vesting criteria were granted to executive officers under the 2013 Equity Plan. These market-based awards cliff vest on the third anniversary of the grant date, and the number of shares that will vest at the end of that three -year performance period will be determined based on the rank of Whiting’s cumulative stockholder return compared to the stockholder return of a peer group of companies over the same three-year period. The number of shares earned could range from zero up to two times the number of shares initially granted. In January 2014 and 2013, 750,681 shares and 751,872 shares, respectively, of restricted stock subject to certain market-based vesting criteria in addition to the standard three -year service condition were granted to executive officers under the 2013 Equity Plan and the 2003 Equity Plan, respectively. Vesting each year is subject to the condition that Whiting’s stock price increases by a greater percentage (or decreases by a lesser percentage) than the average percentage increase (or decrease, respectively) of the stock prices of a peer group of companies. The market-based conditions must be met in order for the stock awards to vest, and it is therefore possible that no shares could vest in one or more of the three-year vesting periods. For service-based restricted stock awards, the grant date fair value is determined based on the closing bid price of the Company’s common stock on the grant date. For the awards subject to market conditions, the grant date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing the market-based restricted shares were as follows: 2015 2014 2013 Number of simulations 2,500,000 65,000 65,000 Expected volatility 40.3% 42.3% 43.1% Risk-free interest rate 0.99% 0.86% 0.41% Dividend yield - - - The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation model was $33.25 per share, $26.59 per share and $23.01 per share in January 2015, 2014 and 2013, respectively. The following table shows a summary of the Company’s nonvested restricted stock as of December 31, 2013, 2014 and 2015 as well as activity during the years then ended: Number of Shares Weighted Average Service-Based Market-Based Grant Date Restricted Stock Restricted Stock Fair Value Nonvested awards, January 1, 2013 244,801 706,225 $ 37.02 Granted 188,920 751,872 27.59 Vested (139,353) (208,471) 35.32 Forfeited (15,263) (84,421) 30.95 Nonvested awards, December 31, 2013 279,105 1,165,205 31.71 Granted 157,175 750,681 32.41 Assumed in Kodiak Acquisition (1) 304,926 - 37.25 Vested (442,584) (371,855) 34.05 Forfeited (17,033) (368,752) 34.86 Nonvested awards, December 31, 2014 281,589 1,175,279 31.16 Granted 824,412 391,773 31.68 Vested (148,838) - 53.26 Forfeited (64,470) (166,089) 30.85 Nonvested awards, December 31, 2015 892,693 1,400,963 $ 30.03 _____________________ (1) Kodiak’s existing restricted stock units and restricted stock awards held by employees, which automatically converted into 257,601 restricted stock units and 47,325 restricted stock awards of Whiting and vested upon closing of the Kodiak Acquisition. As of December 31, 2015, there was $21 million of total unrecognized compensation cost related to unvested restricted stock granted under the stock incentive plans. That cost is expected to be recognized over a weighted average period of 1.8 years. For the years ended December 31, 2015, 2014 and 2013, the total fair value of restricted stock vested was $4 million, $ 31 million and $17 million, respectively. Stock Options . Stock options may be granted to certain executive officers of the Company with exercise prices equal to the closing market price of the Company’s common stock on the grant date. There were no stock options granted under either the 2003 Equity Plan or the 2013 Equity Plan during 2015, 2014 or 2013, other than the 673,235 stock options assumed in connection with the Kodiak Acquisition. The Company’s stock options vest ratably over a three -year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date. The following table shows a summary of the Company’s stock options outstanding as of December 31, 2013, 2014 and 2015 as well as activity during the years then ended : Weighted Average Weighted Aggregate Remaining Average Intrinsic Contractual Number of Exercise Price Value Term Options per Share (in thousands) (in years) Options outstanding at January 1, 2013 422,695 $ 28.79 Granted - - Exercised - - $ - Forfeited or expired (1,855) 60.28 Options outstanding at December 31, 2013 420,840 28.65 Granted - - Assumed in Kodiak Acquisition 673,235 44.48 Exercised (117,123) 15.21 $ 6,203 Forfeited or expired (8,559) 50.51 Options outstanding at December 31, 2014 968,393 41.09 Granted - - Exercised (150,952) 20.75 $ 2,007 Forfeited or expired (229,266) 53.81 Options outstanding at December 31, 2015 588,175 $ 41.35 $ 45 5.5 Options vested and expected to vest at December 31, 2015 558,149 $ 40.84 $ 40 5.5 Options exercisable at December 31, 2015 527,317 $ 39.30 $ 45 5.3 There was $0.1 million of unrecognized compensation cost related to unvested stock option awards as of December 31, 2015. Rights Agreement —In 2006, the Board of Directors of the Company declared a dividend of one preferred share purchase right (a “Right”) for each outstanding share of common stock of the Company payable to the stockholders of record as of March 2, 2006. As a result of the two -for-one split of the Company’s common stock effective February 22, 2011, one -half of a Right is now associated with each share of common stock. Each Right entitles the registered holder to purchase from the Company one one -hundredth of a share of Series A Junior Participating Preferred Stock, par value $0.001 per share (“Preferred Shares”), of the Company at a price of $180.00 per one one-hundredth of a Preferred Share, subject to adjustment. If any person becomes a 15% or more stockholder of the Company, then each Right (subject to certain limitations) will entitle its holder to purchase, at the Right’s then current exercise price, a number of shares of common stock of the Company or of the acquirer having a market value at the time of twice the Right’s per share exercise price. The Company’s Board of Directors may redeem the Rights for $0.001 per Right at any time prior to the time when the Rights become exercisable. The Rights expired on February 23, 2016. Noncontrolling Interest —The Company’s noncontrolling interest represents an unrelated third party’s 25% ownership interest in Sustainable Water Resources, LLC. The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands): Year Ended December 31, 2015 2014 Balance at January 1 $ 8,070 $ 8,132 Net loss (86) (62) Balance at December 31 $ 7,984 $ 8,070

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
INCOME TAXES [Abstract]
INCOME TAXES	10. INCOME TAXES Income tax expense (benefit) consists of the following (in thousands): Year Ended December 31, 2015 2014 2013 Current income tax expense (benefit): Federal $ - $ (2,758) $ 7,060 State (357) 5,383 (6,074) Total current income tax expense (benefit) (357) 2,625 986 Deferred income tax expense (benefit): Federal (736,520) 65,522 196,787 State (37,350) 11,023 8,095 Total deferred income tax expense (benefit) (773,870) 76,545 204,882 Total $ (774,227) $ 79,170 $ 205,868 Income tax expense (benefit) differed from amounts that would result from applying the U.S. statutory income tax rate ( 35%) to income before income taxes as follows (in thousands): Year Ended December 31, 2015 2014 2013 U.S. statutory income tax expense (benefit) $ (1,047,723) $ 50,371 $ 200,155 State income taxes, net of federal benefit (44,654) 12,705 13,962 State income tax credits - - (10,525) Statutory depletion (327) (618) (796) Enacted changes in state tax laws 7,350 3,700 (1,416) Market-based equity awards 2,690 2,805 - Permanent items 5,071 3,504 2,122 Transaction costs - 6,936 - Goodwill impairment 305,820 - - Other (2,454) (233) 2,366 Total $ (774,227) $ 79,170 $ 205,868 The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2015 and 2014 were as follows (in thousands): Year Ended December 31, 2015 2014 Deferred income tax assets: Net operating loss carryforward $ 835,995 $ 588,330 Production Participation Plan liability - 26,942 Asset retirement obligations 18,896 13,791 Underwriter fees 6,060 14,065 Restricted stock compensation 17,675 15,527 Premium on senior notes - 7,979 EOR credit carryforwards 7,946 7,946 Alternative minimum tax credit carryforwards 15,694 15,694 Transaction costs 6,395 7,957 Other 11,110 9,493 Total deferred income tax assets 919,771 707,724 Less valuation allowance (5,061) (5,638) Net deferred income tax assets 914,710 702,086 Deferred income tax liabilities: Oil and gas properties 1,264,598 1,785,926 Trust distributions 101,665 129,437 Discount on convertible senior notes 76,475 - Derivative instruments 65,764 64,898 Total deferred income tax liabilities 1,508,502 1,980,261 Total net deferred income tax liabilities $ 593,792 $ 1,278,175 As of December 31, 2015, the Company had federal net operating loss (“NOL”) carryforwards of $2.3 billion. Of this amount, $ 70 million in NOL carryforwards relate to tax deductions for stock compensation that exceed stock compensation costs recognized for financial statement purposes. The benefit of these excess tax deductions will not be recognized as an NOL in the Company’s financial statements until the related deductions reduce taxes payable and are thereby realized. In addition, the utilization of $72 million of NOL carryforwards incurred as a result of the Kodiak Acquisition are limited for the next year. The Company also has various state NOL carryforwards. The determination of the state NOL carryforwards is dependent upon apportionment percentages and state laws that can change from year to year and that can thereby impact the amount of such carryforwards. If unutilized, the federal NOL will expire between 2023 and 2035, and the state NOLs will expire between 2016 and 2035. EOR credits are a credit against federal income taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed enhanced tertiary recovery methods. As of December 31, 2015, the Company had recognized aggregate EOR credits of $8 million that are available to offset regular federal income taxes in the future. These credits can be carried forward and will expire between 2023 and 2025. Federal EOR credits are subject to phase-out according to the level of average domestic crude oil prices. The EOR credit has been phased-out since 2006, but this phase-out affects only the periods for which EOR credits can be captured and not the periods in which such credits can be utilized. The Company is subject to the alternative minimum tax (“AMT”) principally due to its significant intangible drilling cost deductions. As of December 31, 2015, the Company had AMT credits totaling $16 million that are available to offset future regular federal income taxes. These credits do not expire and can be carried forward indefinitely. At December 31, 2015, the Company had a valuation allowance totaling $5 million, comprised of Canadian NOL carryforwards and foreign tax credit carryforwards, which will expire between 2016 and 2035. These valuation allowances have been recorded because the Company determined it was more likely than not that the benefit from these deferred tax assets will not be realized due to the divestiture of all foreign operations. In conjunction with the Kodiak Acquisition, the Company acquired Kodiak, which is a Canadian entity that is disregarded for U.S. tax purposes. Kodiak holds an interest in Whiting Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.), a U.S. entity. Canadian taxes have not been recognized on the excess of the amount for financial reporting over the tax basis of the investment in Kodiak that is indefinitely reinvested outside the United States. This amount becomes taxable in Canada upon a repatriation of assets from the Canadian subsidiary or a sale or liquidation of the subsidiary. The amount of such temporary differences totaled $729 million as of December 31, 2015. Determination of the amount of any unrecognized deferred Canadian tax liability on this temporary difference is not practicable. U.S. income taxes on Kodiak and its subsidiary, Whiting Resources Corporation, however, have been fully recognized on their cumulative losses to date. In December 2015, the Company adopted ASU 2015-17 on a retrospective basis, which requires all deferred tax assets and liabilities to be presented in the balance sheet as noncurrent. As a result, $48 million of deferred income taxes previously included within current liabilities were reclassified to noncurrent in the Company’s consolidated balance sheet as of December 31, 2014. The Company has an unrecognized tax benefit balance of $170,000 at December 31, 2015, 2014 and 2013 that includes certain tax positions, the allowance of which would positively affect the annual effective income tax rate. For the years ended December 31, 2015, 2014 and 2013, the Company did not recognize any interest or penalties with respect to unrecognized tax benefits, nor did the Company have any such interest or penalties previously accrued. The Company believes that it is reasonably possible that no increases or decreases to unrecognized tax benefits will occur in the next twelve months. The Company files income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2012 through 2015 tax years generally remain subject to examination by federal and state tax authorities. Additionally, in conjunction with the Kodiak Acquisition, the Company has Canadian income tax filings which remain subject to examination by the related tax authorities for the 2010 through 2015 tax years.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2015
EARNINGS PER SHARE [Abstract]
EARNINGS PER SHARE	11. EARNINGS PER SHARE The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data): Year Ended December 31, 2015 2014 2013 Basic Earnings (Loss) Per Share Numerator: Net income (loss) available to shareholders $ (2,219,182) $ 64,807 $ 366,055 Preferred stock dividends (1) - - (494) Net income (loss) available to common shareholders, basic $ (2,219,182) $ 64,807 $ 365,561 Denominator: Weighted average shares outstanding, basic 195,472 122,138 118,260 Diluted Earnings (Loss) Per Share Numerator: Net income (loss) available to common shareholders, basic $ (2,219,182) $ 64,807 $ 365,561 Preferred stock dividends - - 538 Adjusted net income (loss) available to common shareholders, diluted $ (2,219,182) $ 64,807 $ 366,099 Denominator: Weighted average shares outstanding, basic 195,472 122,138 118,260 Restricted stock and stock options - 381 957 Convertible perpetual preferred stock - - 371 Weighted average shares outstanding, diluted 195,472 122,519 119,588 Earnings (loss) per common share, basic $ (11.35) $ 0.53 $ 3.09 Earnings (loss) per common share, diluted $ (11.35) $ 0.53 $ 3.06 _____________________ (1) For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated. There were no accumulated dividend adjustments for the years ended December 31, 2015 or 2014. For the year ended December 31, 2015, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of 516,139 shares of restricted stock and 85,564 stock options. In addition, the diluted earnings per share calculation for the year ended December 31, 2015 excludes (i) the anti-dilutive effect of 676,277 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2015 and (ii) the dilutive effect of 514,757 common shares for stock options that were out-of-the-money. For the year ended December 31, 2014, the diluted earnings per share calculation excludes (i) the dilutive effect of 803,902 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2014, and (ii) the anti-dilutive effect of 791 common shares for stock options that were out-of-the-money. For the year ended December 31, 2013, the diluted earnings per share calculation excludes the dilutive effect of (i) 173,778 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2013, and (ii) 8,689 common shares for stock options that were out-of-the-money.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
RELATED PARTY TRANSACTIONS [Abstract]
RELATED PARTY TRANSACTIONS	12. RELATED PARTY TRANSACTIONS Whiting USA Trust I — Whiting had a retained ownership of 15.8% , or 2,186,389 units in Trust I , and it was therefore a related party of the Company. On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated causing such interest in the underlying properties to revert back to Whiting, and Trust I was no longer a related party. The following table summarizes the related party receivable and payable balances between the Company and Trust I as of December 31, 2014 (in thousands): December 31, 2014 Assets Unit distributions due from Trust I (1) $ 652 Liabilities Unit distributions payable to Trust I (2) $ 4,133 _____________________ (1) This amount represented Whiting’s 15.8% interest in the net proceeds due from Trust I and was included within accounts receivable trade, net in the Company’s consolidated balance sheet. (2) This amount represented net proceeds from Trust I’s underlying properties that the Company had received between the last Trust I distribution date and December 31, 2014, but which the Company had not yet distributed to Trust I as of December 31, 2014. This amount was included within accounts payable trade in the Company’s consolidated balance sheet as of December 31, 2014. Due to processing of Trust I revenues and expenses after December 31, 2014, the amount of Whiting’s actual distribution to Trust I, and the related distribution by Trust I to its unitholders, during the year ended December 31, 2015 was $5 million, net of state tax withholdings, and the Company received $1 million in distributions back from Trust I pursuant to its retained ownership in 2,186,389 Trust I units. Tax Sharing Liability —Prior to Whiting’s initial public offering in November 2003, it was a wholly-owned indirect subsidiary of Alliant Energy Corporation (“Alliant Energy”), and when the transactions discussed below were entered into, Alliant Energy was a related party of the Company. As of December 31, 2004 and thereafter, Alliant Energy was no longer a related party. In 2003, the Company entered into a Tax Separation and Indemnification Agreement with Alliant Energy, whereby the Company and Alliant Energy made certain tax elections with the effect that the tax bases of Whiting’s assets were increased. Such additional tax bases have resulted in increased income tax deductions for Whiting and, accordingly, have reduced income taxes otherwise payable by Whiting. Under this Tax Separation and Indemnification Agreement, the Company agreed to pay to Alliant Energy (each year from 2004 to 2013) 90% of the tax benefits the Company realized annually as a result of this step-up in tax bases. In 2014, Whiting was obligated to pay Alliant the present value of 90% of the remaining tax benefits expected to result from its increased tax bases, which payout assumes all such tax benefits will be realized in future years. In March 2014, the Company made the final payment due Alliant Energy under this agreement totaling $26 million, including $3 million of interest. During 2013, the Company made payments of $2 million under this agreement and recognized interest expense of $3 million. Alliant Energy Guarantee —The Company holds a 6% working interest in three offshore platforms in California and the related onshore plant and equipment. Alliant Energy has guaranteed the Company’s obligation in the abandonment of these assets.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
COMMITMENTS AND CONTINGENCIES [Abstract]
COMMITMENTS AND CONTINGENCIES	13. COMMITMENTS AND CONTINGENCIES The table below shows the Company’s minimum future payments under non-cancelable operating leases and unconditional purchase obligations as of December 31, 2015 (in thousands): Payments due by period 2016 2017 2018 2019 2020 Thereafter Total Non-cancelable leases $ 7,710 $ 6,717 $ 6,693 $ 5,844 $ 216 $ - $ 27,180 Drilling rig contracts 70,120 25,514 - - - - 95,634 Pipeline transportation agreements 5,369 5,369 5,369 5,369 5,369 22,218 49,063 Total $ 83,199 $ 37,600 $ 12,062 $ 11,213 $ 5,585 $ 22,218 $ 171,877 Non-cancelable Leases —The Company leases 204,000 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2019, 47,900 square feet of office space in Midland, Texas expiring in 2020, an additional 36,300 square feet of administrative office space in Denver, Colorado assumed in the Kodiak Acquisition expiring in 2016, and 20,000 square feet of office space in Dickinson, North Dakota expiring in 2016. Rental expense for 2015, 2014 and 2013 amounted to $ 9 million, $7 million and $5 million, respectively. Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 2015 are shown in the table above. Drilling Rig Contracts —As of December 31, 2015, the Company had seven drilling rigs under long-term contract. Subsequent to December 31, 2015, the Company early terminated three of these contracts incurring early termination fees of approximately $24 million. These penalties and the Company’s minimum drilling commitments under the terms of the seven contracts as of December 31, 2015 are shown in the table above. The remaining four long-term contracts expire in 2017. As of December 31, 2015, early termination of the remaining four contracts would require termination penalties of $55 million, which would be in lieu of paying the remaining drilling commitments under these contracts. During 2015, 2014 and 2013, the Company made payments of $161 million, $106 million and $93 million, respectively, under these long-term contracts, which are initially capitalized as a component of oil and gas properties and either depleted in future periods or written off as exploration expense. Pipeline Transportation Agreements— The Company has three ship-or-pay agreements with two different suppliers, one expiring in 2017 and two expiring in 2026, whereby it has committed to transport a minimum daily volume of crude oil, CO 2 or water, as the case may be, via certain pipelines or else pay for any deficiencies at a price stipulated in the contracts. Although minimum daily quantities are specified in the agreements, the actual crude oil, CO 2 or water volumes transported and their corresponding unit prices are variable over the term of the contracts. As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above. As of December 31, 2015, the Company estimated the minimum future commitments under these ship-or-pay agreements to approximate $74 million through 2026. In addition, the Company has two pipeline transportation agreements with one supplier, expiring in 2024 and 2025, whereby it has committed to pay fixed monthly reservation fees on dedicated pipelines for natural gas and NGL transportation capacity, plus a variable charge based on actual transportation volumes. These fixed monthly reservation fees totaling approximately $ 49 million have been included in the table above. During 2015, 2014 and 2013, transportation of crude oil, natural gas, NGLs, CO 2 and water under these contracts amounted to $15 million, $13 million and $4 million, respectively. As of December 31, 2015 , the Company estimated the minimum future commitments under all of these pipeline transportation agreements to approximate $123 million through 2026. Purchase Contracts —The Company has three take-or-pay purchase agreements, of which one agreement expires in 2016, one expires in 2017 and one expires in 2020. One of these agreements contains commitments to buy certain volumes of CO 2 for use in the North Ward Estes EOR project in Texas. Under the remaining two take-or-pay agreements, the Company has committed to buy certain volumes of water for use in the fracture stimulation process of wells in its Redtail field. Under the terms of these agreements, the Company is obligated to purchase a minimum volume of CO 2 or water, as the case may be, or else pay for any deficiencies at the price stipulated in the contract. During 2015, 2014 and 2013, purchases of CO 2 and water amounted to $88 million, $105 million and $84 million, respectively. Although minimum daily quantities are specified in the agreements, the actual CO 2 or water volumes purchased and their corresponding unit prices are variable over the term of the contracts. As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above. As of December 31, 2015, the Company estimated the minimum future commitments under all of these purchase agreements to approximate $107 million through 2020. Water Disposal Agreement —The Company has a water disposal agreement which expires in 2024, whereby it has contracted for the transportation and disposal of the produced water from the Redtail field. Under the terms of the agreement, the Company is obligated to provide a minimum volume of produced water or else pay for any deficiencies at the price stipulated in the contract. There were no water disposal costs incurred under this contract prior to December 31, 2015. Although minimum monthly quantities are specified in the agreements, the actual water volumes disposed of and their corresponding unit prices are variable over the term of the contract. As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above. As of December 31, 2015, the Company estimated the minimum future commitments under this disposal agreement to approximate $146 million through 2024. Delivery Commitments —The Company has various physical delivery contracts which require the Company to deliver fixed volumes of crude oil. As of December 31, 2015, the Company had delivery commitments of 15.6 MMBbl, 25.1 MMBbl, 26.9 MMBbl, 28.8 MMBbl, 11.5 MMBbl, 5.5 MMBbl, 5.5 MMBbl and 4.1 MMBbl of crude oil for the years ended December 31, 2016 through 2023, respectively. One of these delivery commitments is tied to crude oil production at Whiting’s Sanish field in Mountrail County, North Dakota, and two are tied to crude oil production at Whiting’s Redtail field in Weld County, Colorado. The Company believes its production and reserves are sufficient to fulfill the delivery commitment at the Sanish field in North Dakota. However, the Company has determined that it is no longer probable that future oil production from its Redtail field will be sufficient to meet the minimum volume requirements specified in these physical delivery contracts, and as a result, the Company expects to make periodic deficiency payments for any shortfalls in delivering the minimum committed volumes. During 2015, total deficiency payments under these contracts amounted to $15 million. The Company recognizes any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred. Litigation —The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. The Company accrues a loss contingency for these lawsuits and claims when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of the Company’s management that the loss for any litigation matters and claims that are reasonably possible to occur will not have a material adverse effect, individually or in the aggregate, on its consolidated financial position, cash flows or results of operations. Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued at December 31, 2015 or 2014.

OIL AND GAS ACTIVITIES

OIL AND GAS ACTIVITIES	12 Months Ended
	Dec. 31, 2015
OIL AND GAS ACTIVITIES [Abstract]
OIL AND GAS ACTIVITIES	14. OIL AND GAS ACTIVITIES The Company’s oil and gas activities for 2015, 2014 and 2013 were entirely within the United States. Costs incurred in oil and gas producing activities were as follows (in thousands): Year Ended December 31, 2015 2014 2013 Development (1) $ 2,137,755 $ 2,891,893 $ 2,132,824 Proved property acquisition (2) - 2,278,855 232,572 Unproved property acquisition (2) 29,050 1,035,439 174,103 Exploration 192,422 216,587 363,234 Total $ 2,359,227 $ 6,422,774 $ 2,902,733 _____________________ (1) During 2015, 2014 and 2013, non-cash additions to oil and gas properties of $48 million, $45 million and $30 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s oil and gas wells, are included in development costs in the table above. (2) During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property additions related to the Kodiak Acquisition. Net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands): Year Ended December 31, 2015 2014 Proved oil and gas properties $ 12,709,257 $ 12,956,834 Unproved oil and gas properties 1,195,268 1,992,868 Accumulated depletion (3,279,156) (3,003,270) Oil and gas properties, net $ 10,625,369 $ 11,946,432 Exploratory well costs that are incurred and expensed in the same annual period have not been included in the table below. The net changes in capitalized exploratory well costs were as follows (in thousands): Year Ended December 31, 2015 2014 2013 Beginning balance at January 1 $ 14,293 $ 85,378 $ 108,861 Additions to capitalized exploratory well costs pending the determination of proved reserves 54,707 145,336 281,951 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (63,352) (200,869) (291,962) Capitalized exploratory well costs charged to expense (5,648) (15,552) (13,472) Ending balance at December 31 $ - $ 14,293 $ 85,378 At December 31, 2015, the Company had no costs capitalized for exploratory wells in progress for a period of greater than one year after the completion of drilling.

DISCLOSURES ABOUT OIL AND GAS P

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES	12 Months Ended
	Dec. 31, 2015
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract]
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES	15. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) For all years presented, our independent petroleum engineers independently estimated all of the proved reserve quantities included in this Annual Report on Form 10-K. In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests. The independent petroleum engineers, Cawley, Gillespie & Associates, Inc., evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2015. Proved reserve estimates included herein conform to the definitions prescribed by the SEC. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. As of December 31, 2015, all of the Company’s oil and gas reserves are attributable to properties within the United States. A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2013, 2014 and 2015 are as follows: Oil NGLs Natural Gas Total (MBbl) (MBbl) (MMcf) (MBOE) Balance—January 1, 2013 301,285 40,098 224,264 378,760 Extensions and discoveries 88,293 9,830 63,893 108,772 Sales of minerals in place (36,992) (4,777) (12,411) (43,838) Purchases of minerals in place 14,543 1,311 7,751 17,146 Production (27,035) (2,821) (26,917) (34,342) Revisions to previous estimates 7,327 1,228 20,934 12,044 Balance—December 31, 2013 347,421 44,869 277,514 438,542 Extensions and discoveries 146,122 12,947 94,452 174,811 Sales of minerals in place (1,642) - (2,925) (2,130) Purchases of minerals in place 169,586 - 156,140 195,609 Production (33,485) (3,283) (30,218) (41,804) Revisions to previous estimates 15,627 151 (2,943) 15,288 Balance—December 31, 2014 643,629 54,684 492,020 780,316 Extensions and discoveries 131,134 26,074 192,575 189,304 Sales of minerals in place (33,767) (3,240) (96,891) (53,156) Production (47,176) (5,539) (41,129) (59,570) Revisions to previous estimates (97,143) 40,968 119,085 (36,327) Balance—December 31, 2015 596,677 112,947 665,660 820,567 Proved developed reserves: December 31, 2012 190,845 24,204 160,893 241,864 December 31, 2013 198,204 23,721 183,129 252,446 December 31, 2014 333,593 28,935 298,237 412,234 December 31, 2015 298,444 55,437 300,631 403,986 Proved undeveloped reserves: December 31, 2012 110,440 15,894 63,371 136,896 December 31, 2013 149,217 21,148 94,385 186,096 December 31, 2014 310,036 25,749 193,783 368,082 December 31, 2015 298,233 57,510 365,029 416,581 Notable changes in proved reserves for the year ended December 31, 2015 included: · Extensions and discoveries. In 2015, total extensions and discoveries of 189.3 MMBOE were primarily attributable to successful drilling in the Williston Basin and DJ Basin. Both the new wells drilled in these areas as well as the PUD locations added as a result of drilling increased the Company’s proved reserves. · Sales of minerals in place. In 2015, total sales of minerals in place of 53.2 MMBOE were primarily attributable to the disposition of various non-core properties across all our operating areas as further described in the “Acquisitions and Divestitures” footnote, which decreased the Company’s proved reserves. · Revisions to previous estimates. In 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 36.3 MMBOE. Included in these revisions were (i) 82.3 MMBOE of downward adjustments caused by lower crude oil, NGL and natural gas prices at December 31, 2015 as compared to December 31, 2014 incorporated into the Company’s reserve estimates and (ii) 46.0 MMBOE of net upward adjustments attributable to reservoir analysis and well performance. Notable changes in proved reserves for the year ended December 31, 2014 included: · Extensions and discoveries. In 2014, total extensions and discoveries of 174.8 MMBOE were primarily attributable to successful drilling in the Williston Basin and DJ Basin. Both the new wells drilled in these areas as well as the PUD locations added as a result of drilling increased the Company’s proved reserves. · Sales of minerals in place. In 2014, total sales of minerals in place of 2.1 MMBOE were primarily attributable to the disposition of properties in the Big Tex prospect, further described in the “Acquisitions and Divestitures” footnote, as well as other property divestitures in the Lucky Ditch, Whiskey Springs and Bridger Lake fields, which decreased the Company’s proved reserves. · Purchases of minerals in place. In 2014, total purchases of minerals in place of 195.6 MMBOE were primarily attributable to the Kodiak Acquisition, whereby we acquired interests in 778 producing oil and gas wells and undeveloped acreage in the Williston Basin, further described in the “Acquisitions and Divestitures” footnote, which increased the Company’s proved reserves. · Revisions to previous estimates. In 2014, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 15.3 MMBOE. Included in these revisions were (i) 15.6 MMBOE of net upward adjustments attributable to reservoir analysis and well performance and (ii) 0.3 MMBOE of downward adjustments caused by lower crude oil prices at December 31, 2014 as compared to December 31, 2013 incorporated into the Company’s reserve estimates. Notable changes in proved reserves for the year ended December 31, 2013 included: · Extensions and discoveries. In 2013, total extensions and discoveries of 108.8 MMBOE were primarily attributable to successful drilling in the Williston Basin and DJ Basin. Both the new wells drilled in these areas as well as the PUD locations added as a result of drilling increased the Company’s proved reserves. · Sales of minerals in place. In 2013, total sales of minerals in place of 43.8 MMBOE were primarily attributable to the disposition of the Postle Properties, further described in the “Acquisitions and Divestitures” footnote, which decreased the Company’s proved reserves. · Purchases of minerals in place. In 2013, total purchases of minerals in place of 17.1 MMBOE were primarily attributable to the acquisition of 121 producing oil and gas wells and undeveloped acreage in the Williston Basin, further described in the “Acquisitions and Divestitures” footnote, which increased the Company’s proved reserves. · Revisions to previous estimates. In 2013, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 12.0 MMBOE. Included in these revisions were (i) 4.9 MMBOE of upward adjustments caused by higher crude oil and natural gas prices at December 31, 2013 as compared to December 31, 2012 incorporated into the Company’s reserve estimates and (ii) 7.1 MMBOE of net upward adjustments attributable to reservoir analysis and well performance. As discussed in the “Deferred Compensation” footnote, the Company had a Production Participation Plan (the “Plan”) in which all employees participated. On June 11, 2014, the Board of Directors of the Company terminated the Plan effective December 31, 2013. The reserve disclosures above include oil and natural gas reserve volumes that were allocated to the Plan prior to its termination. Once allocated to Plan participants, the interests were fixed. Interest allocations prior to 1995 consisted of 2% – 3% overriding royalty interests. Interest allocations after 1995 were 1.75% – 5% of oil and gas sales less lease operating expenses and production taxes from the production allocated to the Plan. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932, Extractive Activities — Oil and Gas . Future cash inflows as of December 31, 2015, 2014 and 2013 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2015, 2014 and 2013, respectively) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily result in an estimate of the fair value of the Company’s oil and gas properties. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands): December 31, 2015 2014 2013 Future cash flows $ 29,339,528 $ 59,949,707 $ 35,178,399 Future production costs (12,344,463) (20,772,234) (12,973,292) Future development costs (6,166,397) (7,924,573) (5,355,383) Future income tax expense (388,072) (8,579,237) (3,954,401) Future net cash flows 10,440,596 22,673,663 12,895,323 10% annual discount for estimated timing of cash flows (5,866,225) (11,830,243) (6,301,462) Standardized measure of discounted future net cash flows $ 4,574,371 $ 10,843,420 $ 6,593,861 Future cash flows as shown above are reported without consideration for the effects of open hedge contracts at each period end. If the effects of hedging transactions were included in the computation, then undiscounted future cash inflows would have increased by $71 million in 2015, would have decreased by $7 million in 2014 and would not have changed in 2013. The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): December 31, 2015 2014 2013 Beginning of year $ 10,843,420 $ 6,593,861 $ 5,407,033 Sale of oil and gas produced, net of production costs (1,354,054) (2,274,682) (2,010,925) Sales of minerals in place (1,414,511) (48,532) (1,064,195) Net changes in prices and production costs (11,001,949) 81,522 902,916 Extensions, discoveries and improved recoveries 2,078,071 3,950,413 2,827,321 Previously estimated development costs incurred during the period 1,625,160 1,149,926 832,096 Changes in estimated future development costs 102,499 (3,382,849) (1,264,189) Purchases of minerals in place - 4,420,417 445,669 Revisions of previous quantity estimates (966,713) 345,775 313,069 Net change in income taxes 3,578,106 (651,817) (335,637) Accretion of discount 1,084,342 659,386 540,703 End of year $ 4,574,371 $ 10,843,420 $ 6,593,861 Future net revenues included in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves incorporate calculated weighted average sales prices (inclusive of adjustments for quality and location) in effect at December 31, 2015, 2014 and 2013 as follows: 2015 2014 2013 Oil (per Bbl) $ 43.07 $ 84.69 $ 90.80 NGLs (per Bbl) $ 15.53 $ 46.59 $ 54.38 Natural Gas (per Mcf) $ 2.83 $ 5.88 $ 4.30

QUARTERLY FINANCIAL DATA

QUARTERLY FINANCIAL DATA	12 Months Ended
	Dec. 31, 2015
QUARTERLY FINANCIAL DATA [Abstract]
QUARTERLY FINANCIAL DATA	16. QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2015 and 2014 (in thousands, except per share data): Three Months Ended March 31, June 30, September 30, December 31, 2015 2015 2015 2015 Oil, NGL and natural gas sales $ 519,848 $ 650,527 $ 504,155 $ 417,952 Operating profit (loss) (1) $ 25,586 $ 128,012 $ 18,130 $ (60,966) Net loss $ (106,128) $ (149,295) $ (1,865,118) $ (98,727) Basic loss per share $ (0.63) $ (0.73) $ (9.14) $ (0.48) Diluted loss per share $ (0.63) $ (0.73) $ (9.14) $ (0.48) Three Months Ended March 31, June 30, September 30, December 31, 2014 2014 2014 2014 Oil, NGL and natural gas sales $ 721,250 $ 825,760 $ 805,054 $ 672,553 Operating profit (1) $ 311,169 $ 370,033 $ 326,215 $ 177,722 Net income (loss) $ 109,051 $ 151,426 $ 157,961 $ (353,693) Basic earnings (loss) per share $ 0.92 $ 1.27 $ 1.33 $ (2.69) Diluted earnings (loss) per share $ 0.91 $ 1.26 $ 1.32 $ (2.68) _____________________ (1) Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.

SUMMARY OF SIGNIFICANT ACCOUN26

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
Basis of Presentation of Consolidated Financial Statements	Basis of Presentation of Consolidated Financial Statements —The consolidated financial statements include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s 15.8% ownership interest in Trust I. On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated and such interest in the underlying properties reverted back to Whiting. Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method. Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses. All intercompany balances and transactions have been eliminated upon consolidation.
Use of Estimates	Use of Estimates — The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the 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. Items subject to such estimates and assumptions include (1) oil and natural gas reserves; (2) impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) valuations of our business unit used in impairment tests of goodwill; (7) income taxes; (8) accrued liabilities; (9) valuation of derivative instruments; and (10) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents —Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.
Accounts Receivable Trade	Accounts Receivable Trade —Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At December 31, 2015 and 2014, the Company had an allowance for doubtful accounts of $12 million and $9 million, respectively.
Inventories	Inventories — Materials and supplies inventories consist primarily of tubular goods and production equipment, carried at weighted-average cost. Materials and supplies are included in other property and equipment. Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or market value and is included in prepaid expenses and other.
Oil and Gas Properties	Oil and Gas Properties Proved. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a unit-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets’ net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. Fair value for oil and gas properties is generally determined based on discounted future net cash flows. Impairment expense for proved properties is reported in exploration and impairment expense. Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings. Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use. During 2015, 2014 and 2013, the Company capitalized interest of $4 million, $4 million and $2 million, respectively. Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on average lease-term lives and the historical experience of developing acreage in a particular prospect. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense for unproved properties is reported in exploration and impairment expense. Exploratory. Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. Cost incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed. Enhanced recovery activities . The Company carries out tertiary recovery methods on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO 2 , for EOR activities that are used during a project’s pilot phase, or prior to a project’s technical and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO 2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO 2 recycling costs are expensed as incurred. Likewise costs incurred to maintain reservoir pressure are also expensed.
Other Property and Equipment	Other Property and Equipment — Other property and equipment consists of (i) materials and supplies inventories, (ii) leasehold costs and development costs of our CO 2 source properties and (iii) other property and equipment including, furniture and fixtures, buildings, leasehold improvements and automobiles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 4 to 30 years.
Goodwill	Goodwill —Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually in the second quarter or whenever events or changes in circumstances indicate that the fair value of the reporting unit may have been reduced below its carrying value. If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings. The Company performed its annual goodwill impairment test as of June 30, 2015, and determined that no impairment had occurred. However, as a result of a sustained decrease in the price of Whiting’s common stock during the third quarter of 2015 caused by a significant decline in crude oil and natural gas prices over that same period, the Company performed another goodwill impairment test as of September 30, 2015. The impairment test performed by the Company indicated that the fair value of its reporting unit was less than its carrying amount, and further that there was no remaining implied fair value attributable to goodwill. Based on these results, the Company recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero .
Debt Issuance Costs	Debt Issuance Costs —Debt issuance costs related to the Company’s senior notes, convertible senior notes and senior subordinated notes are included as a deduction from the carrying amount of long-term debt in the consolidated balance sheets, and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the credit facility are included in other long-term assets, and are amortized to interest expense on a straight-line basis over the term of the agreement.
Derivative Instruments	Derivative Instruments —The Company enters into derivative contracts, primarily costless collars and swap contracts, to manage its exposure to commodity price risk. All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria, and the derivative has been designated as a hedge. Effective April 1, 2009, however, the Company elected to discontinue all hedge accounting prospectively, and as of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings. Cash flows from derivatives used to manage commodity price risk are classified in operating activities along with the cash flows of the underlying hedged transactions. The Company does not enter into derivative instruments for speculative or trading purposes.
Asset Retirement Obligations and Environmental Costs	Asset Retirement Obligations and Environmental Costs —Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or when an asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a unit-of-production basis over the proved developed reserves of the related asset. Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability. Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties.
Deferred Gain On Sales	Deferred Gain on Sale —The deferred gain on sale relates to the sale of 11,677,500 Trust I units and 18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the unit-of-production method. In January 2015, the deferred gain on sale related to Trust I was fully amortized in connection with the termination of the trust’s net profits interest.
Revenue Recognition	Revenue Recognition —Oil and gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, persuasive evidence of a sales arrangement exists and collectability of the revenue is reasonably assured. Revenues from the production of gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest (entitlement method). Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as receivables. The Company’s aggregate imbalance positions as of December 31, 2015 and 2014 were not significant. Taxes collected and remitted to governmental agencies on behalf of customers are not included in revenues or costs and expenses.
General and Administrative Expenses	General and Administrative Expenses —General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to the working interest owners that participate in oil and gas properties operated by Whiting.
Acquisition Cost	Acquisition Costs — Acquisition related expenses, which consist of external costs directly related to the Company’s acquisitions, such as advisory, legal, accounting, valuation and other professional fees, are expensed as incurred.
Maintenance and Repairs	Maintenance and Repairs —Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred. Major replacements, renewals and betterments are capitalized.
Income Taxes	Income Taxes —Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense.
Earnings Per Share	Earnings Per Share —Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period. Diluted earnings per common share is calculated by dividing adjusted net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards, outstanding stock options and contingently issuable shares of convertible debt, all using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury stock method to the extent that such excess tax benefits are more likely than not to be realized. In addition, to the extent the conversion value of the convertible debt exceeds the aggregate principal amount of the notes, such conversion spread is included in the diluted earnings per share computation under the treasury stock method. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.
Industry Segment and Geographic Information	Industry Segment and Geographic Information —The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.
Concentration of Credit Risk	Concentration of Credit Risk —Whiting is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review. For the year ended December 31, 2015, no individual purchaser accounted for 10% or more of the Company’s total oil, NGL and natural gas sales. The following table presents the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2014 and 2013: 2014 2013 Plains Marketing LP 17% 21% Shell Trading US 10% 14% Bridger Trading LLC 10% 8% Eighty Eight Oil Company 6% 11% Commodity derivative contracts held by the Company are with six counterparties, all of which are participants in Whiting’s credit facility as well, and all of which have investment-grade ratings from Moody’s and Standard & Poor. As of December 31, 2015, outstanding derivative contracts with JP Morgan Chase Bank, N.A. represented 76% of total crude oil volumes hedged.
Reclassifications	Reclassifications —Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
Adopted and Recently Issued Accounting Pronouncements	Adopted and Recently Issued Accounting Pronouncements — In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014 ‑09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, however, in August 2015, the FASB issued Accounting Standards Update No. 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date (“ASU 2015-14”), which deferred the effective date of ASU 2014 ‑09 for one year. ASU 2015-14 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permit retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application. The Company is currently evaluating the impact of adopting ASU 2014 ‑09 and ASU 2015-14, including the transition method to be applied, however the standards are not expected to have a significant effect on its consolidated financial statements. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016 and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s consolidated financial statements. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”). The objective of ASU 2015-03 is to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (“ASU 2015-15”). This ASU amends ASU 2015-03 which had not addressed the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under ASU 2015-15, a Company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. ASU 2015-03 and ASU 2015-15 are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, should be applied retrospectively and represent a change in accounting principle. Early adoption is permitted. The Company adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2015, and as a result, $26 million of debt issuance costs related to the Company’s senior notes, convertible senior notes, and senior subordinated notes were reclassified from other long-term assets to long-term debt in the Company’s consolidated balance sheet as of December 31, 2014. The Company elected to continue presenting the debt issuance costs associated with its credit facility as other long-term assets in the consolidated balance sheets. In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”). This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively. Early adoption is permitted. The adoption of this standard will not have a material impact on the Company’s consolidated financial statements. In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). This ASU eliminates the requirement to retrospectively apply measurement-period adjustments made to provisional amounts recognized in a business combination. Under ASU 2015-16, the cumulative impact of a measurement-period adjustment (including the impact on prior periods) should instead be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. This standard should be applied prospectively, and early adoption is permitted. The adoption of this standard is not expected to have a significant impact on the Company’s consolidated financial statements. In November 2015, the FASB issued Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). The objective of this ASU is to simplify the financial statement presentation of deferred taxes by presenting both current and noncurrent deferred tax assets and liabilities as noncurrent on the balance sheet. ASU 2015-17 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. This standard may be applied either prospectively or retrospectively to all periods presented, and early adoption is permitted. The Company adopted ASU 2015-17 as of December 31, 2015 on a retrospective basis, which represents a change in accounting principle. As a result, $48 million of deferred income taxes previously included within current liabilities were reclassified to noncurrent in the Company’s consolidated balance sheet as of December 31, 2014. In January 2016, the FASB issued Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). This ASU amends the guidance in U.S. GAAP on financial instruments specifically related to (i) the classification and measurement of investments in equity securities, (ii) the presentation of certain fair value changes for financial liabilities measured at fair value and (iii) certain disclosure requirements associated with the fair value of financial instruments. ASU 2016-01 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted only for the provisions of this ASU related to FASB ASC 825, Financial Instruments . A cumulative-effect adjustment to beginning retained earnings is required as of the beginning of the fiscal year in which this ASU is adopted. The adoption of this standard is not expected to have a significant impact on the Company’s consolidated financial statements.

FAIR VALUE MEASUREMENTS (Policy

FAIR VALUE MEASUREMENTS (Policy)	12 Months Ended
	Dec. 31, 2015
FAIR VALUE MEASUREMENTS [Abstract]
Fair Value of Financial Instruments	Cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates. The Company’s senior notes, convertible senior notes and senior subordinated notes are recorded at cost, and the fair values of these instruments are included in the “Long-Term Debt” footnote. The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparties, as appropriate.

SUMMARY OF SIGNIFICANT ACCOUN28

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2015
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
Percentages of total oil and gas sales to significant purchasers	2014 2013 Plains Marketing LP 17% 21% Shell Trading US 10% 14% Bridger Trading LLC 10% 8% Eighty Eight Oil Company 6% 11%

OIL AND GAS PROPERTIES (Tables)

OIL AND GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2015
OIL AND GAS PROPERTIES [Abstract]
Net capitalized costs related to oil and gas producing activities	December 31, 2015 2014 Proved leasehold costs $ 3,206,237 $ 3,637,026 Unproved leasehold costs 689,754 1,232,040 Costs of completed wells and facilities 9,503,020 9,319,808 Wells and facilities in progress 505,514 760,828 Total oil and gas properties, successful efforts method 13,904,525 14,949,702 Accumulated depletion (3,279,156) (3,003,270) Oil and gas properties, net $ 10,625,369 $ 11,946,432

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2015
Significant Acquisitions and Disposals [Line Items]
Changes in goodwill	Gross Carrying Amount Accumulated Impairment Losses Net Carrying Amount Balance, January 1, 2014 $ - $ - $ - Goodwill acquired 875,676 - 875,676 Balance, December 31, 2014 875,676 - 875,676 Adjustments to previously recorded goodwill (1,904) - (1,904) Impairment losses - (873,772) (873,772) Balance, December 31, 2015 $ 873,772 $ (873,772) $ -
Williston Basin [Member]
Significant Acquisitions and Disposals [Line Items]
Assets acquired and liabilities assumed	Purchase price $ 255,537 Allocation of purchase price: Oil and gas properties, successful efforts method: Proved properties $ 229,002 Unproved properties 27,335 Oil in tank inventory 522 Accounts receivable 578 Asset retirement obligations (1,900) Total $ 255,537
Kodiak [Member]
Significant Acquisitions and Disposals [Line Items]
Assets acquired and liabilities assumed	Consideration: Fair value of Whiting’s common stock issued (1) $ 1,771,094 Fair value of Kodiak restricted stock units assumed by Whiting (2) 9,596 Fair value of Kodiak options assumed by Whiting 7,523 Total consideration $ 1,788,213 Fair value of liabilities assumed: Accounts payable trade $ 18,390 Accrued capital expenditures 97,848 Revenues and royalties payable 57,423 Accrued interest 18,070 Accrued liabilities and other 43,563 Taxes payable 12,807 Long-term debt 2,500,875 Deferred tax liability 31,034 Asset retirement obligations 8,646 Other long-term liabilities 15,735 Amount attributable to liabilities assumed $ 2,804,391 Fair value of assets acquired: Cash and cash equivalents $ 18,879 Accounts receivable trade, net 215,654 Derivative assets 85,718 Prepaid expenses and other 8,523 Oil and gas properties, successful efforts method: Proved properties 2,266,607 Unproved properties 1,000,396 Other property and equipment 11,347 Deferred tax asset 106,758 Other long-term assets 4,950 Amount attributable to assets acquired $ 3,718,832 Goodwill $ 873,772 _____________________ (1) 47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s 268,622,497 common shares outstanding at closing. (2) 257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5 , 2014), based on Kodiak’s 1,455,409 restricted stock units held by employees as of December 8, 2014.
Unaudited pro forma operating results	December 31, 2014 2013 (in thousands, except per share data) Total revenues $ 4,141,046 $ 3,774,137 Net income available to common shareholders $ 362,376 $ 576,450 Earnings per common share: Basic $ 2.18 $ 3.48 Diluted $ 2.17 $ 3.46

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
LONG-TERM DEBT [Abstract]
Schedule of long-term debt	December 31, 2015 2014 Credit agreement $ 800,000 $ 1,400,000 6.5% Senior Subordinated Notes due 2018 350,000 350,000 5% Senior Notes due 2019 1,100,000 1,100,000 8.125% Senior Notes due 2019 - 800,000 1.25% Convertible Senior Notes due 2020 1,250,000 - 5.75% Senior Notes due 2021 1,200,000 1,200,000 5.5% Senior Notes due 2021 - 350,000 5.5% Senior Notes due 2022 - 400,000 6.25% Senior Notes due 2023 750,000 - Total principal 5,450,000 5,600,000 Debt discounts and premiums (203,082) 28,782 Debt issuance costs on notes (49,214) (26,393) Total long-term debt $ 5,197,704 $ 5,602,389
Schedule of five succeeding fiscal years of scheduled maturities for the Company's long-term debt	2016 2017 2018 2019 2020 Long-term debt $ - $ - $ 350,000 $ 1,900,000 $ 1,250,000
Summary of margin rates and commitment fees	Applicable Applicable Margin for Base Margin for Commitment Ratio of Outstanding Borrowings to Borrowing Base Rate Loans Eurodollar Loans Fee Less than 0.25 to 1.0 0.50% 1.50% 0.375% Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 0.75% 1.75% 0.375% Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 1.00% 2.00% 0.50% Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 1.25% 2.25% 0.50% Greater than or equal to 0.90 to 1.0 1.50% 2.50% 0.50%
Schedule of convertible senior notes	Liability component: Principal $ 1,250,000 Less: note discount (205,572) Net carrying value $ 1,044,428 Equity component (1) $ 237,500 (1) Recorded in additional paid-in capital, net of $5 million of issuance costs and $88 million of deferred taxes.

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2015
ASSET RETIREMENT OBLIGATIONS [Abstract]
Schedule of reconciliation of the Company's asset retirement obligations	December 31, 2015 2014 Asset retirement obligation at January 1 $ 179,931 $ 126,148 Additional liability incurred 9,208 29,186 Revisions to estimated cash flows (1) 29,307 25,909 Accretion expense 20,274 13,548 Obligations on sold properties (69,601) (7,237) Liabilities settled (7,211) (7,623) Asset retirement obligation at December 31 $ 161,908 $ 179,931 (1) Revisions in estimated cash flows during the years ended December 31, 2015 and 2014 are primarily attributable to increased estimates of future costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains and Permian Basin regions.

DERIVATIVE FINANCIAL INSTRUME33

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Financial Instruments [Line Items]
Schedule of effects of commodity derivative instruments	Loss Reclassified from AOCI into Income (Effective Portion) ASC 815 Cash Flow Statement of Operations Year Ended December 31, Hedging Relationships (1) Classification 2015 2014 2013 Commodity contracts Loss on hedging activities $ - $ - $ (1,958) ____________________ (1) Effective April 1, 2009, the Company de-designated all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions affected income. As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings. (Gain) Loss Recognized in Income Not Designated as Statement of Operations Year Ended December 31, ASC 815 Hedges Classification 2015 2014 2013 Commodity contracts Commodity derivative (gain) loss, net $ (217,972) $ (136,995) $ 20,503 Embedded commodity contracts Commodity derivative (gain) loss, net - 36,416 (12,701) Total $ (217,972) $ (100,579) $ 7,802
Location and fair value of derivative instruments	December 31, 2015 (1) Net Gross Recognized Recognized Gross Fair Value Not Designated as Assets/ Amounts Assets/ ASC 815 Hedges Balance Sheet Classification Liabilities Offset Liabilities Derivative assets: Commodity contracts - current Derivative assets $ 258,778 $ (100,049) $ 158,729 Commodity contracts - non-current Other long-term assets 31,415 (3,465) 27,950 Total derivative assets $ 290,193 $ (103,514) $ 186,679 Derivative liabilities: Commodity contracts - current Accrued liabilities and other $ 101,214 $ (100,049) $ 1,165 Commodity contracts - non-current Other long-term liabilities 6,327 (3,465) 2,862 Total derivative liabilities $ 107,541 $ (103,514) $ 4,027 December 31, 2014 (1) Net Gross Recognized Recognized Gross Fair Value Not Designated as Assets/ Amounts Assets/ ASC 815 Hedges Balance Sheet Classification Liabilities Offset Liabilities Derivative assets: Commodity contracts - current Derivative assets $ 154,329 $ (18,752) $ 135,577 Commodity contracts - non-current Other long-term assets 45,459 - 45,459 Total derivative assets $ 199,788 $ (18,752) $ 181,036 Derivative liabilities: Commodity contracts - current Accrued liabilities and other $ 18,752 $ (18,752) $ - Total derivative liabilities $ 18,752 $ (18,752) $ - _____________________ (1) Because counterparties to the Company’s financial derivative contracts are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above.
Whiting Petroleum Corporation [Member]
Derivative Financial Instruments [Line Items]
Derivative instruments	Whiting Petroleum Corporation Derivative Contracted Crude Weighted Average NYMEX Price Instrument Period Oil Volumes (Bbl) Collar Ranges for Crude Oil (per Bbl) Three-way collars (1) Jan - Dec 2016 16,800,000 $43.75 - $53.75 - $74.40 Collars Jan - Dec 2016 3,000,000 $51.00 - $63.48 Jan - Dec 2017 3,000,000 $53.00 - $70.44 Total 22,800,000 _____________________ (1) A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
FAIR VALUE MEASUREMENTS [Abstract]
Fair value assets and liabilities measured on a recurring basis	Total Fair Value Level 1 Level 2 Level 3 December 31, 2015 Financial Assets Commodity derivatives – current $ - $ 158,729 $ - $ 158,729 Commodity derivatives – non-current - 27,950 - 27,950 Total financial assets $ - $ 186,679 $ - $ 186,679 Financial Liabilities Commodity derivatives – current $ - $ - $ 1,165 $ 1,165 Commodity derivatives – non-current - - 2,862 2,862 Total financial liabilities $ - $ - $ 4,027 $ 4,027 Total Fair Value Level 1 Level 2 Level 3 December 31, 2014 Financial Assets Commodity derivatives – current $ - $ 127,506 $ 8,071 $ 135,577 Commodity derivatives – non-current - - 45,459 45,459 Total financial assets $ - $ 127,506 $ 53,530 $ 181,036
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy	Year Ended December 31, 2015 2014 Fair value asset, beginning of period $ 53,530 $ 36,416 Unrealized gains (losses) on commodity derivative contracts included in earnings (1) (24,018) 17,114 Commodity derivative contract settlements (33,539) - Transfers into (out of) Level 3 - - Fair value asset (liability), end of period $ (4,027) $ 53,530 _____________________ (1) Included in commodity derivative (gain) loss, net in the consolidated statements of operations.
Significant unobservable inputs used in the fair value measurement	Fair Value at December 31, 2015 Valuation Unobservable Amount (in thousands) Technique Input (per Bbl) Commodity derivative contract ($4,027) Income approach Market differential for crude oil $5.25
Non-financial assets and liabilities measured at fair value on a nonrecurring basis	Loss (Before Net Carrying Tax) Year Value as of Ended September 30, Fair Value Measurements Using December 31, 2015 Level 1 Level 2 Level 3 2015 Proved property (1) $ 531,775 $ - $ - $ 531,775 $ 1,602,226 Goodwill (2) - - - - 873,772 Total non-recurring assets at fair value $ 531,775 $ - $ - $ 531,775 $ 2,475,998 _____________________ (1) During the third quarter of 2015, proved oil and gas properties with a previous carrying amount of $2.1 billion were written down to their fair value as of September 30, 2015 of $531 million, resulting in a non-cash impairment charge of $1.5 billion which was recorded within exploration and impairment expense. The impaired properties consisted of the Company’s North Ward Estes field in Texas and other non-core proved oil and gas properties primarily in Texas, Wyoming, North Dakota and Colorado that are not currently being developed due to depressed oil and gas prices. Also during the third quarter of 2015, proved CO 2 properties at the Bravo Dome field in New Mexico and the McElmo Dome field in Colorado with a previous carrying amount of $63 million were written down to their fair value as of September 30, 2015 of $1 million, resulting in a non-cash impairment charge of $62 million which was also recorded within exploration and impairment expense. (2) During 2015, goodwill related to the Kodiak Acquisition with a carrying amount of $874 million was written down to its fair value of zero , resulting in a non-cash impairment charge of $874 million which was recorded as a separate line in the consolidated statements of operations. Loss (Before Net Carrying Tax) Year Value as of Ended December 31, Fair Value Measurements Using December 31, 2014 Level 1 Level 2 Level 3 2014 Proved property (1) $ 179,155 $ - $ - $ 179,155 $ 629,450 _____________________ (1) During the fourth quarter of 2014, proved oil and gas properties with a previous carrying amount of $763 million were written down to their fair value as of December 31, 2014 of $176 million, resulting in a non-cash impairment charge of $587 million which was recorded within exploration and impairment expense. The impaired properties consisted of non-core proved oil and gas properties primarily in Colorado, Louisiana, North Dakota and Utah that were not being developed due to depressed oil and gas prices as of December 31, 2014. Also during the fourth quarter of 2014, proved CO 2 properties at the Bravo Dome field in New Mexico with a previous carrying amount of $45 million were written down to their fair value as of December 31, 2014 of $3 million, resulting in a non-cash impairment charge of $42 million which was also recorded within exploration and impairment expense.

SHAREHOLDERS' EQUITY AND NONC35

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Tables)	12 Months Ended
	Dec. 31, 2015
Business Acquisition [Line Items]
Assumption for valuing market based restricted shares	2015 2014 2013 Number of simulations 2,500,000 65,000 65,000 Expected volatility 40.3% 42.3% 43.1% Risk-free interest rate 0.99% 0.86% 0.41% Dividend yield - - -
Summary of nonvested restricted stock	Number of Shares Weighted Average Service-Based Market-Based Grant Date Restricted Stock Restricted Stock Fair Value Nonvested awards, January 1, 2013 244,801 706,225 $ 37.02 Granted 188,920 751,872 27.59 Vested (139,353) (208,471) 35.32 Forfeited (15,263) (84,421) 30.95 Nonvested awards, December 31, 2013 279,105 1,165,205 31.71 Granted 157,175 750,681 32.41 Assumed in Kodiak Acquisition (1) 304,926 - 37.25 Vested (442,584) (371,855) 34.05 Forfeited (17,033) (368,752) 34.86 Nonvested awards, December 31, 2014 281,589 1,175,279 31.16 Granted 824,412 391,773 31.68 Vested (148,838) - 53.26 Forfeited (64,470) (166,089) 30.85 Nonvested awards, December 31, 2015 892,693 1,400,963 $ 30.03 _____________________ (1) Kodiak’s existing restricted stock units and restricted stock awards held by employees, which automatically converted into 257,601 restricted stock units and 47,325 restricted stock awards of Whiting and vested upon closing of the Kodiak Acquisition.
Summary of stock options outstanding	Weighted Average Weighted Aggregate Remaining Average Intrinsic Contractual Number of Exercise Price Value Term Options per Share (in thousands) (in years) Options outstanding at January 1, 2013 422,695 $ 28.79 Granted - - Exercised - - $ - Forfeited or expired (1,855) 60.28 Options outstanding at December 31, 2013 420,840 28.65 Granted - - Assumed in Kodiak Acquisition 673,235 44.48 Exercised (117,123) 15.21 $ 6,203 Forfeited or expired (8,559) 50.51 Options outstanding at December 31, 2014 968,393 41.09 Granted - - Exercised (150,952) 20.75 $ 2,007 Forfeited or expired (229,266) 53.81 Options outstanding at December 31, 2015 588,175 $ 41.35 $ 45 5.5 Options vested and expected to vest at December 31, 2015 558,149 $ 40.84 $ 40 5.5 Options exercisable at December 31, 2015 527,317 $ 39.30 $ 45 5.3
Schedule of noncontrolling interest	Year Ended December 31, 2015 2014 Balance at January 1 $ 8,070 $ 8,132 Net loss (86) (62) Balance at December 31 $ 7,984 $ 8,070
Kodiak [Member]
Business Acquisition [Line Items]
Assumption for valuing market based restricted shares	2014 Risk-free interest rate 0.08% - 1.90% Expected volatility 40.3% - 49.7% Expected term 2.0 yrs. - 6.1 yrs. Dividend yield -

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
INCOME TAXES [Abstract]
Schedule of income tax expense	Year Ended December 31, 2015 2014 2013 Current income tax expense (benefit): Federal $ - $ (2,758) $ 7,060 State (357) 5,383 (6,074) Total current income tax expense (benefit) (357) 2,625 986 Deferred income tax expense (benefit): Federal (736,520) 65,522 196,787 State (37,350) 11,023 8,095 Total deferred income tax expense (benefit) (773,870) 76,545 204,882 Total $ (774,227) $ 79,170 $ 205,868
Reconciliation of statutory income tax expense to income tax expense	Year Ended December 31, 2015 2014 2013 U.S. statutory income tax expense (benefit) $ (1,047,723) $ 50,371 $ 200,155 State income taxes, net of federal benefit (44,654) 12,705 13,962 State income tax credits - - (10,525) Statutory depletion (327) (618) (796) Enacted changes in state tax laws 7,350 3,700 (1,416) Market-based equity awards 2,690 2,805 - Permanent items 5,071 3,504 2,122 Transaction costs - 6,936 - Goodwill impairment 305,820 - - Other (2,454) (233) 2,366 Total $ (774,227) $ 79,170 $ 205,868
Components of deferred income tax assets and liabilities	Year Ended December 31, 2015 2014 Deferred income tax assets: Net operating loss carryforward $ 835,995 $ 588,330 Production Participation Plan liability - 26,942 Asset retirement obligations 18,896 13,791 Underwriter fees 6,060 14,065 Restricted stock compensation 17,675 15,527 Premium on senior notes - 7,979 EOR credit carryforwards 7,946 7,946 Alternative minimum tax credit carryforwards 15,694 15,694 Transaction costs 6,395 7,957 Other 11,110 9,493 Total deferred income tax assets 919,771 707,724 Less valuation allowance (5,061) (5,638) Net deferred income tax assets 914,710 702,086 Deferred income tax liabilities: Oil and gas properties 1,264,598 1,785,926 Trust distributions 101,665 129,437 Discount on convertible senior notes 76,475 - Derivative instruments 65,764 64,898 Total deferred income tax liabilities 1,508,502 1,980,261 Total net deferred income tax liabilities $ 593,792 $ 1,278,175

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2015
EARNINGS PER SHARE [Abstract]
Reconciliations between basic and diluted earnings per share	Year Ended December 31, 2015 2014 2013 Basic Earnings (Loss) Per Share Numerator: Net income (loss) available to shareholders $ (2,219,182) $ 64,807 $ 366,055 Preferred stock dividends (1) - - (494) Net income (loss) available to common shareholders, basic $ (2,219,182) $ 64,807 $ 365,561 Denominator: Weighted average shares outstanding, basic 195,472 122,138 118,260 Diluted Earnings (Loss) Per Share Numerator: Net income (loss) available to common shareholders, basic $ (2,219,182) $ 64,807 $ 365,561 Preferred stock dividends - - 538 Adjusted net income (loss) available to common shareholders, diluted $ (2,219,182) $ 64,807 $ 366,099 Denominator: Weighted average shares outstanding, basic 195,472 122,138 118,260 Restricted stock and stock options - 381 957 Convertible perpetual preferred stock - - 371 Weighted average shares outstanding, diluted 195,472 122,519 119,588 Earnings (loss) per common share, basic $ (11.35) $ 0.53 $ 3.09 Earnings (loss) per common share, diluted $ (11.35) $ 0.53 $ 3.06 _____________________ (1) For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated. There were no accumulated dividend adjustments for the years ended December 31, 2015 or 2014.

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2015
RELATED PARTY TRANSACTIONS [Abstract]
Summary of related party receivable and payable balances	December 31, 2014 Assets Unit distributions due from Trust I (1) $ 652 Liabilities Unit distributions payable to Trust I (2) $ 4,133 _____________________ (1) This amount represented Whiting’s 15.8% interest in the net proceeds due from Trust I and was included within accounts receivable trade, net in the Company’s consolidated balance sheet. (2) This amount represented net proceeds from Trust I’s underlying properties that the Company had received between the last Trust I distribution date and December 31, 2014, but which the Company had not yet distributed to Trust I as of December 31, 2014. This amount was included within accounts payable trade in the Company’s consolidated balance sheet as of December 31, 2014. Due to processing of Trust I revenues and expenses after December 31, 2014, the amount of Whiting’s actual distribution to Trust I, and the related distribution by Trust I to its unitholders, during the year ended December 31, 2015 was $5 million, net of state tax withholdings, and the Company received $1 million in distributions back from Trust I pursuant to its retained ownership in 2,186,389 Trust I units.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2015
COMMITMENTS AND CONTINGENCIES [Abstract]
Minimum future payments under non-cancelable operating leases and unconditional purchase obligations	Payments due by period 2016 2017 2018 2019 2020 Thereafter Total Non-cancelable leases $ 7,710 $ 6,717 $ 6,693 $ 5,844 $ 216 $ - $ 27,180 Drilling rig contracts 70,120 25,514 - - - - 95,634 Pipeline transportation agreements 5,369 5,369 5,369 5,369 5,369 22,218 49,063 Total $ 83,199 $ 37,600 $ 12,062 $ 11,213 $ 5,585 $ 22,218 $ 171,877

OIL AND GAS ACTIVITIES (Tables)

OIL AND GAS ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2015
OIL AND GAS ACTIVITIES [Abstract]
Schedule of cost Incurred in oil and gas producing activities	Year Ended December 31, 2015 2014 2013 Development (1) $ 2,137,755 $ 2,891,893 $ 2,132,824 Proved property acquisition (2) - 2,278,855 232,572 Unproved property acquisition (2) 29,050 1,035,439 174,103 Exploration 192,422 216,587 363,234 Total $ 2,359,227 $ 6,422,774 $ 2,902,733 _____________________ (1) During 2015, 2014 and 2013, non-cash additions to oil and gas properties of $48 million, $45 million and $30 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s oil and gas wells, are included in development costs in the table above. (2) During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property additions related to the Kodiak Acquisition.
Net capitalized costs related to the Company’s oil and gas producing activities	Year Ended December 31, 2015 2014 Proved oil and gas properties $ 12,709,257 $ 12,956,834 Unproved oil and gas properties 1,195,268 1,992,868 Accumulated depletion (3,279,156) (3,003,270) Oil and gas properties, net $ 10,625,369 $ 11,946,432
Net changes in capitalized exploratory well costs	Year Ended December 31, 2015 2014 2013 Beginning balance at January 1 $ 14,293 $ 85,378 $ 108,861 Additions to capitalized exploratory well costs pending the determination of proved reserves 54,707 145,336 281,951 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (63,352) (200,869) (291,962) Capitalized exploratory well costs charged to expense (5,648) (15,552) (13,472) Ending balance at December 31 $ - $ 14,293 $ 85,378

DISCLOSURES ABOUT OIL AND GAS41

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2015
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract]
Summary of changes in quantities of proved oil and gas reserve	Oil NGLs Natural Gas Total (MBbl) (MBbl) (MMcf) (MBOE) Balance—January 1, 2013 301,285 40,098 224,264 378,760 Extensions and discoveries 88,293 9,830 63,893 108,772 Sales of minerals in place (36,992) (4,777) (12,411) (43,838) Purchases of minerals in place 14,543 1,311 7,751 17,146 Production (27,035) (2,821) (26,917) (34,342) Revisions to previous estimates 7,327 1,228 20,934 12,044 Balance—December 31, 2013 347,421 44,869 277,514 438,542 Extensions and discoveries 146,122 12,947 94,452 174,811 Sales of minerals in place (1,642) - (2,925) (2,130) Purchases of minerals in place 169,586 - 156,140 195,609 Production (33,485) (3,283) (30,218) (41,804) Revisions to previous estimates 15,627 151 (2,943) 15,288 Balance—December 31, 2014 643,629 54,684 492,020 780,316 Extensions and discoveries 131,134 26,074 192,575 189,304 Sales of minerals in place (33,767) (3,240) (96,891) (53,156) Production (47,176) (5,539) (41,129) (59,570) Revisions to previous estimates (97,143) 40,968 119,085 (36,327) Balance—December 31, 2015 596,677 112,947 665,660 820,567 Proved developed reserves: December 31, 2012 190,845 24,204 160,893 241,864 December 31, 2013 198,204 23,721 183,129 252,446 December 31, 2014 333,593 28,935 298,237 412,234 December 31, 2015 298,444 55,437 300,631 403,986 Proved undeveloped reserves: December 31, 2012 110,440 15,894 63,371 136,896 December 31, 2013 149,217 21,148 94,385 186,096 December 31, 2014 310,036 25,749 193,783 368,082 December 31, 2015 298,233 57,510 365,029 416,581
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	December 31, 2015 2014 2013 Future cash flows $ 29,339,528 $ 59,949,707 $ 35,178,399 Future production costs (12,344,463) (20,772,234) (12,973,292) Future development costs (6,166,397) (7,924,573) (5,355,383) Future income tax expense (388,072) (8,579,237) (3,954,401) Future net cash flows 10,440,596 22,673,663 12,895,323 10% annual discount for estimated timing of cash flows (5,866,225) (11,830,243) (6,301,462) Standardized measure of discounted future net cash flows $ 4,574,371 $ 10,843,420 $ 6,593,861
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	December 31, 2015 2014 2013 Beginning of year $ 10,843,420 $ 6,593,861 $ 5,407,033 Sale of oil and gas produced, net of production costs (1,354,054) (2,274,682) (2,010,925) Sales of minerals in place (1,414,511) (48,532) (1,064,195) Net changes in prices and production costs (11,001,949) 81,522 902,916 Extensions, discoveries and improved recoveries 2,078,071 3,950,413 2,827,321 Previously estimated development costs incurred during the period 1,625,160 1,149,926 832,096 Changes in estimated future development costs 102,499 (3,382,849) (1,264,189) Purchases of minerals in place - 4,420,417 445,669 Revisions of previous quantity estimates (966,713) 345,775 313,069 Net change in income taxes 3,578,106 (651,817) (335,637) Accretion of discount 1,084,342 659,386 540,703 End of year $ 4,574,371 $ 10,843,420 $ 6,593,861
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves calculating average sales prices	2015 2014 2013 Oil (per Bbl) $ 43.07 $ 84.69 $ 90.80 NGLs (per Bbl) $ 15.53 $ 46.59 $ 54.38 Natural Gas (per Mcf) $ 2.83 $ 5.88 $ 4.30

QUARTERLY FINANCIAL DATA (Table

QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2015
QUARTERLY FINANCIAL DATA [Abstract]
Summary of the unaudited quarterly financial data	Three Months Ended March 31, June 30, September 30, December 31, 2015 2015 2015 2015 Oil, NGL and natural gas sales $ 519,848 $ 650,527 $ 504,155 $ 417,952 Operating profit (loss) (1) $ 25,586 $ 128,012 $ 18,130 $ (60,966) Net loss $ (106,128) $ (149,295) $ (1,865,118) $ (98,727) Basic loss per share $ (0.63) $ (0.73) $ (9.14) $ (0.48) Diluted loss per share $ (0.63) $ (0.73) $ (9.14) $ (0.48) Three Months Ended March 31, June 30, September 30, December 31, 2014 2014 2014 2014 Oil, NGL and natural gas sales $ 721,250 $ 825,760 $ 805,054 $ 672,553 Operating profit (1) $ 311,169 $ 370,033 $ 326,215 $ 177,722 Net income (loss) $ 109,051 $ 151,426 $ 157,961 $ (353,693) Basic earnings (loss) per share $ 0.92 $ 1.27 $ 1.33 $ (2.69) Diluted earnings (loss) per share $ 0.91 $ 1.26 $ 1.32 $ (2.68) _____________________ (1) Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.

SUMMARY OF SIGNIFICANT ACCOUN43

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative I) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 08, 2015
Summary Of Significant Accounting Policies [Line Items]
Oil and gas receivables collection period	2 months
Allowance for doubtful account	$ 12,000	$ 9,000
Interest cost capitalized	4,000	$ 4,000	$ 2,000
Goodwill	$ 0			$ 874,000
Whiting USA Trust I [Member]
Summary Of Significant Accounting Policies [Line Items]
Company retained ownership (as a percent)	15.80%
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life	4 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life	30 years

SUMMARY OF SIGNIFICANT ACCOUN44

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative II) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)segmentitemshares	Dec. 31, 2014USD ($)
Concentration Risk [Line Items]
Number of operating segments | segment	1
Debt issuance costs	$ 49,214	$ 26,393
Non-current deferred income taxes	$ 593,792	1,278,175
Adjustments for New Accounting Principle, Early Adoption [Member]
Concentration Risk [Line Items]
Debt issuance costs		26,000
Non-current deferred income taxes		$ 48,000
Whiting USA Trust I [Member]
Concentration Risk [Line Items]
Trust units sold to the public (in shares) | shares	11,677,500
Whiting USA Trust II Units [Member]
Concentration Risk [Line Items]
Trust units sold to the public (in shares) | shares	18,400,000
Commodity Price Risk [Member] | Derivative Contracts [Member]
Concentration Risk [Line Items]
Number of counterparties | item	6
JP Morgan Chase [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member]
Concentration Risk [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged	76.00%

SUMMARY OF SIGNIFICANT ACCOUN45

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Percentages of total oil and gas sales to significant purchases) (Details) - Credit Concentration Risk [Member] - Oil And Gas Sales [Member]	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Plains Marketing LP [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	17.00%	21.00%
Shell Trading US [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	10.00%	14.00%
Bridger Trading LLC [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	10.00%	8.00%
Eighty Eight Oil Company [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	6.00%	11.00%

OIL AND GAS PROPERTIES (Details

OIL AND GAS PROPERTIES (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
OIL AND GAS PROPERTIES [Abstract]
Proved leasehold costs	$ 3,206,237	$ 3,637,026
Unproved leasehold costs	689,754	1,232,040
Costs of completed wells and facilities	9,503,020	9,319,808
Wells and facilities in progress	505,514	760,828
Total oil and gas properties, successful efforts method	13,904,525	14,949,702
Accumulated depletion	(3,279,156)	(3,003,270)
Oil and gas properties, net	$ 10,625,369	$ 11,946,432

ACQUISITIONS AND DIVESTITURES47

ACQUISITIONS AND DIVESTITURES (Narrative I) (Details) $ / shares in Units, $ in Thousands	Jun. 01, 2015USD ($)stateitem	May. 01, 2015USD ($)stateitem	Dec. 08, 2014USD ($)aitemshares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 05, 2014$ / shares	Dec. 31, 2013USD ($)
Business Acquisition [Line Items]
Proceeds from sale	$ 150,000	$ 108,000		$ 75,000
Gain (loss) on sale	$ (118,000)	$ 29,000
Number of well sold | item	2,000
Number of fields, in which sold wells are located | item	132	187
Number of states, in which sold wells are located | state	10	14
Goodwill adjustment since acquisition						$ 1,904
Goodwill related to acquisition							$ 875,676
Goodwill deductible for income tax purposes				$ 0		$ 0
Goodwill					$ 875,676		$ 875,676
Non-Core Producing Oil And Gas Wells And Undeveloped Acreage [Member]
Business Acquisition [Line Items]
Proceeds from sale						$ 176,000
Gain (loss) on sale				$ 28,000		28,000
Kodiak [Member]
Business Acquisition [Line Items]
Shares exchanged per each share owned | shares			0.177
Total consideration			$ 1,788,213
Aggregate purchase price			4,300,000
Outstanding debt			2,500,000
Cash acquired from acquisition			$ 19,000
Gross acquisition area (in acres) | a			327,000
Net acquisition area (in acres) | a			178,000
Number of wells acquired | item			778
Goodwill adjustment since acquisition						2,000
Goodwill			$ 873,772	$ 0		$ 0
Revenue					46,000
Net income					$ 17,000
Kodiak [Member] | Wyoming And Colorado [Member]
Business Acquisition [Line Items]
Net acquisition area (in acres) | a			10,000
Common Stock [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Awards Assumed in Kodiak Acquisition (in shares) | shares			47,546,139
Closing price, per share | $ / shares								$ 37.25

ACQUISITIONS AND DIVESTITURES48

ACQUISITIONS AND DIVESTITURES (Narrative II) (Details) $ in Thousands	Jun. 01, 2015USD ($)	May. 01, 2015USD ($)	Mar. 27, 2014USD ($)a	Oct. 31, 2013USD ($)a	Jul. 15, 2013USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2013USD ($)	Sep. 20, 2013USD ($)aitem
Acquisitions and divestitures [Line Items]
Proceeds from sale	$ 150,000	$ 108,000				$ 75,000
Pre tax gain on Divestiture	$ (118,000)	$ 29,000
Williston Basin [Member]
Acquisitions and divestitures [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds									$ 261,000
Gross acquisition area (in acres) | a									39,300
Net acquisition area (in acres) | a									17,300
Number of wells acquired | item									121
Post-closing purchase price adjustments							$ 6,000
Adjusted purchase price of tangible assets acquired and liabilities assumed								$ 255,537
Big Tex prospect properties [Member]
Acquisitions and divestitures [Line Items]
Gross acquisition area (in acres) | a			49,900	45,000
Net acquisition area (in acres) | a			41,000	32,200
Proceeds from sale			$ 76,000	$ 151,000
Pre tax gain on Divestiture			$ 12,000	$ 11,000
Big Tex prospect properties [Member] | Pecos County, TX [Member]
Acquisitions and divestitures [Line Items]
Net acquisition area (in acres) | a				30,800
Big Tex prospect properties [Member] | Reeves County, TX [Member]
Acquisitions and divestitures [Line Items]
Net acquisition area (in acres) | a				1,400
Postle Properties [Member]
Acquisitions and divestitures [Line Items]
Ownership interest sold (as a percent)					60.00%
Proceeds from sale					$ 809,000
Pre tax gain on Divestiture					$ 109,000

ACQUISITIONS AND DIVESTITURES49

ACQUISITIONS AND DIVESTITURES (Preliminary Consideration Transferred) (Details) - USD ($) $ / shares in Units, $ in Thousands		Dec. 08, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 05, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Proved properties			$ 12,709,257	$ 12,956,834
Unproved properties			$ 689,754	1,232,040
Goodwill				$ 875,676
Common stock, shares issued			206,441,303	168,346,020
Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Closing price, per share					$ 37.25
Stock Option [Member]
Business Acquisition [Line Items]
Awards Assumed in Kodiak Acquisition (in shares)			673,235	673,235
Kodiak [Member] | Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Common stock, shares issued		1,455,409
Kodiak [Member]
Business Acquisition [Line Items]
Total consideration		$ 1,788,213
Accounts payable trade		18,390
Accrued capital expenditures		97,848
Revenues and royalties payable		57,423
Accrued interest		18,070
Accrued liabilities and other		43,563
Taxes payable		12,807
Long-term debt		2,500,875
Deferred tax liability		31,034
Asset retirement obligations		8,646
Other long-term liabilities		15,735
Amount attributable to liabilities assumed		2,804,391
Cash and cash equivalents		18,879
Accounts receivable trade, net		215,654
Derivative assets		85,718
Prepaid expenses and other		8,523
Proved properties		2,266,607
Unproved properties		1,000,396
Other property and equipment		11,347
Deferred tax asset		106,758
Other long-term assets		4,950
Amount attributable to assets acquired		3,718,832
Goodwill		$ 873,772	$ 0
Common Stock [Member] | Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Awards Assumed in Kodiak Acquisition (in shares)		257,601
Common Stock [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Common stock, shares issued		268,622,497
Common Stock [Member] | Kodiak [Member] | Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Fair value of Whiting’s common stock issued	[1]	$ 9,596
Common Stock [Member] | Kodiak [Member] | Stock Option [Member]
Business Acquisition [Line Items]
Fair value of Whiting’s common stock issued		$ 7,523
Common Stock [Member]
Business Acquisition [Line Items]
Closing price, per share					$ 37.25
Common Stock [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Awards Assumed in Kodiak Acquisition (in shares)		47,546,139
Common Stock [Member] | Common Stock [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Fair value of Whiting’s common stock issued	[2]	$ 1,771,094
[1]	257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiak's 1,455,409 restricted stock units held by employees as of December 8, 2014.
[2]	47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiak's 268,622,497 common shares outstanding at closing.

ACQUISITIONS AND DIVESTITURES50

ACQUISITIONS AND DIVESTITURES (Changes in the Goodwill) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015
ACQUISITIONS AND DIVESTITURES [Abstract]
Gross Carrying Amount, Beginning Balance	$ 875,676
Accumulated Impairment Losses, Beginning Balance
Goodwill, Beginning Balance	$ 875,676
Goodwill acquired		$ 875,676
Adjustments to previously recorded goodwill	(1,904)
Impairment losses	(873,772)
Goodwill, Gross	875,676		$ 873,772
Accumulated Impairment Losses, Ending Balance	$ (873,772)
Goodwill, Ending Balance		$ 875,676

ACQUISITIONS AND DIVESTITURES51

ACQUISITIONS AND DIVESTITURES (Purchase price allocation) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2013
Significant Acquisitions and Disposals [Line Items]
Proved properties	$ 12,709,257	$ 12,956,834
Unproved properties	$ 689,754	$ 1,232,040
Williston Basin [Member]
Significant Acquisitions and Disposals [Line Items]
Proved properties			$ 229,002
Unproved properties			27,335
Oil in tank inventory			522
Accounts receivable			578
Asset retirement obligations			(1,900)
Total			$ 255,537

ACQUISITIONS AND DIVESTITURES52

ACQUISITIONS AND DIVESTITURES (Unaudited Pro forma Operating Results) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Acquisition-related Costs [Member]
Business Acquisition [Line Items]
Acquisition-related costs	$ 86,000
Kodiak [Member]
Business Acquisition [Line Items]
Total revenues	4,141,046	$ 3,774,137
Net income available to common shareholders	$ 362,376	$ 576,450
Net income (loss) per share: Basic	$ 2.18	$ 3.48
Net income (loss) per share: Diluted	$ 2.17	$ 3.46

LONG-TERM DEBT (Credit agreemen

LONG-TERM DEBT (Credit agreement) (Details) - Whiting Oil and Gas Corporation [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Oct. 31, 2015
Debt disclosures [Line Items]
Maximum borrowing capacity of credit facility	$ 4,000,000	$ 4,500,000
Credit Agreement [Member]
Debt disclosures [Line Items]
Maximum borrowing capacity of credit facility	4,000,000
Maximum aggregate commitments	3,500,000
Borrowing capacity of credit facility, net of letter of credit	2,700,000
Outstanding borrowings under credit facility	800,000
Letters of credit borrowings outstanding	2,000
Portion of line of credit available for issuance of letters of credit	100,000
Amount of revolving credit agreement available for additional letters of credit under the agreement	$ 98,000
Weighted average interest rate	1.90%
Retained earnings free from restrictions	$ 0
Minimum consolidated current assets to consolidated current liabilities ratio (percentage)	1
Total senior secured debt to EBITDAX ratio (percentage)	2.5
EBITDAX to consolidated interest charges	2.25
Credit Agreement [Member] | April 1, 2018 Or Commencement Of An Investment-Grade Debt Rating Period [Member]
Debt disclosures [Line Items]
Total debt to EBITDAX ratio (percentage)	4
Credit Agreement [Member] | Base Rate [Member]
Debt disclosures [Line Items]
Basis points added to reference rate (as a percent)	0.50%
Variable interest rate basis	federal funds
Credit Agreement [Member] | LIBOR [Member]
Debt disclosures [Line Items]
Basis points added to reference rate (as a percent)	1.00%
Variable interest rate basis	LIBOR

LONG-TERM DEBT (Schedule of lon

LONG-TERM DEBT (Schedule of long-term debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Sep. 26, 2013	Sep. 30, 2010
Debt Instrument [Line Items]
Total principal	$ 5,450,000	$ 5,600,000
Debt discounts and premiums	(203,082)	28,782
Debt issuance cost on notes	(49,214)	(26,393)
Total long-term bebt	5,197,704	5,602,389
Credit Agreement [Member]
Debt Instrument [Line Items]
Total principal	800,000	1,400,000
Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member]
Debt Instrument [Line Items]
Total principal	$ 350,000	$ 350,000
Interest rate on debt instrument (as a percent)	6.50%	6.50%				6.50%
Senior Notes [Member] | 5% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Total principal	$ 1,100,000	$ 1,100,000
Interest rate on debt instrument (as a percent)	5.00%	5.00%	5.00%	5.00%
Senior Notes [Member] | 8.125% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Total principal		$ 800,000
Interest rate on debt instrument (as a percent)	8.125%	8.125%
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Total principal	$ 1,200,000	$ 1,200,000
Interest rate on debt instrument (as a percent)	5.75%	5.75%	5.75%	5.75%	5.75%
Senior Notes [Member] | 5.5% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Total principal		$ 350,000
Interest rate on debt instrument (as a percent)	5.50%	5.50%
Senior Notes [Member] | 5.5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Total principal		$ 400,000
Interest rate on debt instrument (as a percent)	5.50%
Senior Notes [Member] | 6.25% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Total principal	$ 750,000
Interest rate on debt instrument (as a percent)	6.25%
Convertible Senior Notes [Member] | 1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Total principal	$ 1,250,000
Interest rate on debt instrument (as a percent)	1.25%

LONG-TERM DEBT (Schedule of fiv

LONG-TERM DEBT (Schedule of five succeeding fiscal years of scheduled maturities for long-term debt) (Details) $ in Thousands	Dec. 31, 2015USD ($)
LONG-TERM DEBT [Abstract]
2,018	$ 350,000
2,019	1,900,000
2,020	$ 1,250,000

LONG-TERM DEBT (Summary of marg

LONG-TERM DEBT (Summary of margin rates and commitment fees) (Details) - Credit Agreement [Member] - Whiting Oil and Gas Corporation [Member]	12 Months Ended
	Dec. 31, 2015
Base Rate [Member]
Debt Instrument [Line Items]
Variable interest rate basis	federal funds
Applicable Margin for Loans (as percent)	0.50%
Less than 0.25 to 1.0 [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Alternate variable interest rate basis	base loan rate
Range, less than	0.25
Commitment Fee (as a percent)	0.375%
Less than 0.25 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	0.50%
Less than 0.25 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.50%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Alternate variable interest rate basis	base loan rate
Range, greater than or equal to	0.25
Range, less than	0.50
Commitment Fee (as a percent)	0.375%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	0.75%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.75%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Alternate variable interest rate basis	base loan rate
Range, greater than or equal to	0.50
Range, less than	0.75
Commitment Fee (as a percent)	0.50%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.00%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	2.00%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Alternate variable interest rate basis	base loan rate
Range, greater than or equal to	0.75
Range, less than	0.90
Commitment Fee (as a percent)	0.50%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.25%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	2.25%
Greater than or equal to 0.90 to 1.0 [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Alternate variable interest rate basis	base loan rate
Range, greater than or equal to	0.90
Commitment Fee (as a percent)	0.50%
Greater than or equal to 0.90 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.50%
Greater than or equal to 0.90 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	2.50%

LONG-TERM DEBT (Senior notes an

LONG-TERM DEBT (Senior notes and senior subordinated notes) (Details) - USD ($)	Dec. 24, 2015	May. 01, 2015	Mar. 06, 2015	Jan. 07, 2015	Oct. 31, 2013	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2014	Dec. 08, 2014	Sep. 30, 2013	Sep. 26, 2013	Sep. 30, 2010
Debt disclosures [Line Items]
Payment for redemption of senior debt							$ 253,988,000
Loss on early extinguishment of debt						$ (18,361,000)	$ (4,412,000)
Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)						6.50%		6.50%				6.50%
Notes Issued												$ 350,000,000
Estimated fair value of Notes						$ 265,000,000		$ 345,000,000
Senior Subordinated Notes [Member] | 7% Senior Subordinated Notes due 2014 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)							7.00%
Notes repurchased, principal amount					$ 250,000,000
Payment for redemption of senior debt					$ 254,000,000
Percentage of redemption price					101.595%
Loss on early extinguishment of debt					$ 4,000,000
Cash charge related to the redemption premium					$ 4,000,000
Senior Notes [Member] | 5% Senior Notes due 2019 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)						5.00%	5.00%	5.00%		5.00%
Notes Issued										$ 1,100,000,000
Estimated fair value of Notes						$ 831,000,000		$ 1,000,000,000
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)						5.75%	5.75%	5.75%		5.75%	5.75%
Notes Issued										$ 800,000,000	$ 400,000,000
Debt premium amount											$ 4,000,000
Debt, effective interest rate						5.50%
Estimated fair value of Notes						$ 870,000,000		$ 1,100,000,000
Premium as a percentage of par											101.00%
Senior Notes [Member] | 8.125% Senior Notes due 2019 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)						8.125%		8.125%
Notes Issued						$ 800,000,000
Notes repurchased, principal amount	$ 798,000,000
Estimated fair value of Notes								$ 812,000,000	$ 824,000,000
Repurchase of notes			$ 2,000,000			$ 832,429,000
Senior Notes [Member] | 5.5% Senior Notes due 2021 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)						5.50%		5.50%
Notes Issued						$ 350,000,000
Notes repurchased, principal amount		$ 4,000,000
Estimated fair value of Notes								$ 351,000,000	351,000,000
Repurchase of notes			346,000,000			$ 353,500,000
Senior Notes [Member] | 5.5% Senior Notes due 2022 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)						5.50%
Notes Issued						$ 400,000,000
Notes repurchased, principal amount		1,000,000
Estimated fair value of Notes								$ 401,000,000	$ 401,000,000
Repurchase of notes			399,000,000			404,000,000
Senior Notes [Member] | Repurchased Kodiak Notes [Member]
Debt disclosures [Line Items]
Notes repurchased, principal amount		$ 5,000,000
Repurchase of notes	$ 834,000,000		$ 760,000,000
Percentage of redemption price	104.063%	101.00%
Loss on early extinguishment of debt						(18,000,000)
Cash charge related to the redemption premium						40,000,000
Non cash charges						$ 22,000,000
Senior Notes [Member] | 6.25% Senior Notes due 2023 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)						6.25%
Notes Issued						$ 750,000,000
Estimated fair value of Notes						$ 544,000,000
Senior Notes [Member] | 5.5% Kodiak Senior Notes due 2022 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)								5.50%
Senior Notes [Member] | Kodiak [Member]
Debt disclosures [Line Items]
Notes Issued				$ 1,550,000,000
Percentage of redemption price				101.00%

LONG-TERM DEBT (Convertible sen

LONG-TERM DEBT (Convertible senior notes) (Details)	12 Months Ended
	Dec. 31, 2015USD ($)item$ / shares$ / item	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Mar. 31, 2015USD ($)
Debt Instrument [Line Items]
Interest expense	$ 334,125,000	$ 170,642,000	$ 112,936,000
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Principal	$ 1,250,000,000
Interest rate on debt instrument (as a percent)	1.25%
Net proceeds	$ 1,200,000,000
Underwriter's fees	$ 25,000,000
Debt maturity date	Apr. 1, 2020
Principal amount per conversion ratio | $ / item	1,000
Conversion ratio	25.6410
Conversion price per $1,000 principal amount of notes | $ / shares	$ 39
Debt, effective interest rate	5.60%
Carrying value of convertible debt	$ 1,044,428,000
Debt discount	205,572,000			$ 238,000,000
Estimated fair value of Notes	850,000,000
Interest expense	$ 44,000,000
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes [Member] | Convertible Senior Notes, Conversion Scenario 1 [Member]
Debt Instrument [Line Items]
Minimum days within 30 consecutive days of trading, where percent of conversion price exceed agreed upon percentage | item	20
Debt Instrument, Convertible, Threshold Consecutive Trading Days	30 days
Minimum conversion price percentage used to determine settlement of conversion	130.00%
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes [Member] | Convertible Senior Notes, Conversion Scenario 2 [Member]
Debt Instrument [Line Items]
Debt Instruments Convertible Threshold Consecutive Trading Days	5 days
Period after measurement period used for convertible senior notes	5 days
Principal amount per conversion ratio | $ / item	1,000
Threshold percentage of product of stock price and conversion rate	98.00%

LONG-TERM DEBT (Schedule of con

LONG-TERM DEBT (Schedule of convertible senior notes) (Details) - Convertible Senior Notes [Member] - 1.25% Convertible Senior Notes due 2020 [Member] - USD ($)		12 Months Ended
		Dec. 31, 2015	Mar. 31, 2015
Debt Instrument [Line Items]
Principal		$ 1,250,000,000
Less: note discount		(205,572,000)	$ (238,000,000)
Net carrying value		1,044,428,000
Equity component	[1]	237,500,000
Debt Issuance Cost		25,000,000
Equity Component Of Convertible Senior Note [Member]
Debt Instrument [Line Items]
Debt Issuance Cost		5,000
Equity component of convertible debt, deferred taxes		$ 88,000
[1]	Recorded in additional paid-in capital, net of $5 million of issuance costs and $88 million of deferred taxes.

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations
Asset retirement obligations, current portion		$ 6,000	$ 12,000
Reconciliation of the Company's asset retirement obligations
Balance at the beginning of the period		179,931	126,148
Additional liability incurred		9,208	29,186
Revisions to estimated cash flows	[1]	29,307	25,909
Accretion expense		20,274	13,548
Obligations on sold properties		(69,601)	(7,237)
Liabilities settled		(7,211)	(7,623)
Balance at the end of the period		$ 161,908	$ 179,931
[1]	Revisions in estimated cash flows during the years ended December 31, 2015 and 2014 are primarily attributable to increased estimates of future costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains and Permian Basin regions.

DERIVATIVE FINANCIAL INSTRUME61

DERIVATIVE FINANCIAL INSTRUMENTS (Derivative instruments) (Details) - Whiting Petroleum Corporation [Member] - Crude oil [Member] - Subsequent Event [Member]	Jan. 01, 2016item$ / bbl
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl) | item	22,800,000
Three-way collars [Member] | Jan - Dec 2016 [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl) | item	16,800,000	[1]
Derivative, Floor Price (in dollars per Bbl)	43.75	[1]
Derivative, Strike Price (in dollars per Bbl)	53.75	[1]
Derivative, Cap Price (in dollars per Bbl)	74.40	[1]
Collars [Member] | Jan - Dec 2016 [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl) | item	3,000,000
Derivative, Floor Price (in dollars per Bbl)	51
Derivative, Cap Price (in dollars per Bbl)	63.48
Collars [Member] | Jan - Dec 2017 [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl) | item	3,000,000
Derivative, Floor Price (in dollars per Bbl)	53
Derivative, Cap Price (in dollars per Bbl)	70.44
[1]	A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.

DERIVATIVE FINANCIAL INSTRUME62

DERIVATIVE FINANCIAL INSTRUMENTS (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Financial Instruments [Line Items]
Embedded commodity derivative contracts, fair value	$ 0
Level 3 [Member]
Derivative Financial Instruments [Line Items]
Fair value liabilities	$ (4,027)	$ 53,530	$ 36,416

DERIVATIVE FINANCIAL INSTRUME63

DERIVATIVE FINANCIAL INSTRUMENTS (Schedule of effects of commodity derivative instruments) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income		$ (217,972)	$ (100,579)	$ 7,802
Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income		(217,972)	(100,579)	7,802
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income		$ (217,972)	(136,995)	20,503
Commodity contracts [Member] | ASC 815 Cash Flow Hedging Relationships [Member]
Derivative Financial Instruments [Line Items]
Loss Reclassified from AOCI into Income (Effective Portion)	[1]			(1,958)
Embedded commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income			$ 36,416	$ (12,701)
[1]	Effective April 1, 2009, the Company de-designated all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a result, such mark-to-market values at March 31, 2009 were frozen in accumulated other comprehensive income ("AOCI") as of the de-designation date and were reclassified into earnings as the original hedged transactions affected income. The OCI amortization amount on the de-designated hedges was reclassified from AOCI to loss on hedging activities in the consolidated statements of operations. As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings.

DERIVATIVE FINANCIAL INSTRUME64

DERIVATIVE FINANCIAL INSTRUMENTS (Location and fair value of derivative instruments, assets) (Details) - Not Designated as ASC 815 Hedges [Member] - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	[1]	$ 290,193	$ 199,788
Gross Amounts Offset	[1]	(103,514)	(18,752)
Total financial assets	[1]	186,679	181,036
Commodity contracts [Member] | Derivative Assets [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	[1]	258,778	154,329
Gross Amounts Offset	[1]	(100,049)	(18,752)
Total financial assets	[1]	158,729	135,577
Commodity contracts [Member] | Other Long Term Assets [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	[1]	31,415	45,459
Gross Amounts Offset	[1]	(3,465)
Total financial assets	[1]	$ 27,950	$ 45,459
[1]	Because counterparties to the Company's financial derivative contracts are lenders under Whiting Oil and Gas' credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above.

DERIVATIVE FINANCIAL INSTRUME65

DERIVATIVE FINANCIAL INSTRUMENTS (Location and fair value of derivative instruments, liabilities) (Details) - Not Designated as ASC 815 Hedges [Member] - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Gross amounts of derivative liabilities and gross amounts offset [Line Items]
Gross Amounts of Recognized Liabilities	[1]	$ 107,541	$ 18,752
Gross Amounts Offset	[1]	(103,514)	(18,752)
Total financial liabilities	[1]	4,027
Commodity contracts [Member] | Accrued Liabilities And Other [Member]
Gross amounts of derivative liabilities and gross amounts offset [Line Items]
Gross Amounts of Recognized Liabilities	[1]	101,214	18,752
Gross Amounts Offset	[1]	(100,049)	$ (18,752)
Total financial liabilities	[1]	1,165
Commodity contracts [Member] | Other Long-Term Liabilities [Member]
Gross amounts of derivative liabilities and gross amounts offset [Line Items]
Gross Amounts of Recognized Liabilities	[1]	6,327
Gross Amounts Offset	[1]	(3,465)
Total financial liabilities	[1]	$ 2,862
[1]	Because counterparties to the Company's financial derivative contracts are lenders under Whiting Oil and Gas' credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above.

FAIR VALUE MEASUREMENTS (Fair v

FAIR VALUE MEASUREMENTS (Fair value assets and liabilities measured on a recurring basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Financial Assets
Financial assets - current	$ 158,729	$ 135,577
Recurring Basis [Member]
Financial Assets
Total financial assets	186,679	181,036
Financial Liabilities
Total financial liabilities	4,027
Recurring Basis [Member] | Commodity contracts [Member]
Financial Assets
Financial assets - current	158,729	135,577
Financial assets - non-current	27,950	45,459
Financial Liabilities
Financial liabilities - current	1,165
Financial liabilities - non-current	2,862
Recurring Basis [Member] | Level 2 [Member]
Financial Assets
Total financial assets	186,679	127,506
Recurring Basis [Member] | Level 2 [Member] | Commodity contracts [Member]
Financial Assets
Financial assets - current	158,729	127,506
Financial assets - non-current	27,950
Recurring Basis [Member] | Level 3 [Member]
Financial Assets
Total financial assets		53,530
Financial Liabilities
Total financial liabilities	4,027
Recurring Basis [Member] | Level 3 [Member] | Commodity contracts [Member]
Financial Assets
Financial assets - current		8,071
Financial assets - non-current		$ 45,459
Financial Liabilities
Financial liabilities - current	1,165
Financial liabilities - non-current	$ 2,862

FAIR VALUE MEASUREMENTS (Reconc

FAIR VALUE MEASUREMENTS (Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy)(Details) - Level 3 [Member] - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy
Fair value asset, beginning of period		$ 53,530	$ 36,416
Unrealized gains (losses) on commodity derivative contracts included in earnings	[1]	(24,018)	17,114
Commodity derivative contract settlements		(33,539)
Fair value asset (liability), end of period		$ (4,027)	$ 53,530
[1]	Included in commodity derivative (gain) loss, net in the consolidated statements of operations.

FAIR VALUE MEASUREMENTS (Signif

FAIR VALUE MEASUREMENTS (Significant unobservable inputs used in the fair value measurement) (Details) - Level 3 [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / bbl	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Fair value (liability)	$ (4,027)	$ 53,530	$ 36,416
Commodity contracts [Member]
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Fair value (liability)	$ (4,027)
Market Differential For Crude Oil, Amount (Per Bbl) | $ / bbl	5.25

FAIR VALUE MEASUREMENTS (Non-fi

FAIR VALUE MEASUREMENTS (Non-financial assets and liabilities measured at fair value on a nonrecurring basis) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 08, 2015	Sep. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Goodwill		$ 0				$ 874,000
Goodwill impairment		873,772
Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total non-recurring assets at fair value							$ 531,775
Non-recurring assets at fair value, Impairment Loss (Before Tax)		2,475,998
Goodwill impairment	[1]	873,772
Nonrecurring [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total non-recurring assets at fair value							531,775
Nonrecurring [Member] | Proved Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property				$ 179,155	[2]		531,775	[3]
Non-recurring assets at fair value, Impairment Loss (Before Tax)		1,602,226	[3]	629,450	[2]
Nonrecurring [Member] | Proved Properties [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property				179,155	[2]		531,775	[3]
Nonrecurring [Member] | Proved Oil and Natural Gas Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property				176,000			531,000
Non-recurring assets at fair value, Impairment Loss (Before Tax)		1,500,000		587,000
Proved Oil and Gas Properties, Net Carrying Value				763,000			2,100,000
Nonrecurring [Member] | Proved CO2 Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property				3,000			1,000
Non-recurring assets at fair value, Impairment Loss (Before Tax)		$ 62,000		42,000
CO2 Properties, Net Carrying Value				$ 45,000			$ 63,000
[1]	During 2015, goodwill related to the Kodiak Acquisition with a carrying amount of $874 million was written down to its fair value of zero, resulting in a non-cash impairment charge of $874 million which was recorded as a separate line in the consolidated statements of operations.
[2]	During the fourth quarter of 2014, proved oil and gas properties with a previous carrying amount of $763 million were written down to their fair value as of December 31, 2014 of $176 million, resulting in a non-cash impairment charge of $587 million which was recorded within exploration and impairment expense. The impaired properties consisted of non-core proved oil and gas properties primarily in Colorado, Louisiana, North Dakota and Utah that were not being developed due to depressed oil and gas prices as of December 31, 2014. Also during the fourth quarter of 2014, proved CO2 properties at the Bravo Dome field in New Mexico with a previous carrying amount of $45 million were written down to their fair value as of December 31, 2014 of $3 million, resulting in a non-cash impairment charge of $42 million which was also recorded within exploration and impairment expense.
[3]	During the third quarter of 2015, proved oil and gas properties with a previous carrying amount of $2.1 billion were written down to their fair value as of September 30, 2015 of $531 million, resulting in a non-cash impairment charge of $1.5 billion which was recorded within exploration and impairment expense. The impaired properties consisted of the Company's North Ward Estes field in Texas and other non-core proved oil and gas properties primarily in Texas, Wyoming, North Dakota and Colorado that are not currently being developed due to depressed oil and gas prices. Also during the third quarter of 2015, proved CO2 properties at the Bravo Dome field in New Mexico and the McElmo Dome field in Colorado with a previous carrying amount of $63 million were written down to their fair value as of September 30, 2015 of $1 million, resulting in a non-cash impairment charge of $62 million which was also recorded within exploration and impairment expense.

DEFERRED COMPENSATION (Producti

DEFERRED COMPENSATION (Production Participation Plan) (Details) - USD ($) $ in Thousands	12 Months Ended				252 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 1995	Dec. 31, 1994	Dec. 31, 2015
Deferred Compensation [Line Items]
Amount reflected as a current liability		$ 113,391
Additional Deferred Compensation
Percentage of employees vesting ratably per year	20.00%
Plan period (years)	5 years
Distribution period after date of termination (months)	12 months
Minimum [Member]
Deferred Compensation [Line Items]
Percentage of overriding royalty interest allocated				2.00%
Percentage of oil and gas sales less lease operating expenses and production taxes allocated		1.75%	1.75%		1.75%
Maximum [Member]
Deferred Compensation [Line Items]
Percentage of overriding royalty interest allocated				3.00%
Percentage of oil and gas sales less lease operating expenses and production taxes allocated		5.00%	5.00%		5.00%
General and administrative expense [Member]
Deferred Compensation [Line Items]
Accrued compensation expense allocation		$ 24,000
Exploration expense [Member]
Deferred Compensation [Line Items]
Accrued compensation expense allocation		$ 2,000

DEFERRED COMPENSATION (401K Pla

DEFERRED COMPENSATION (401K Plan) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
DEFERRED COMPENSATION [Abstract]
Employer's contribution in employees retirement plan	$ 12	$ 9	$ 8
Employees vest in employer contribution Percentage, per year of completed service	20.00%

SHAREHOLDERS' EQUITY AND NONC72

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (6.25% Convertible perpetual preferred stock) (Details) - $ / shares	Mar. 31, 2013	Jun. 30, 2009	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014
Convertible perpetual preferred stock [Member]
Class of Stock [Line Items]
Interest rate on convertible perpetual preferred stock (as a percent)		6.25%
6.25% convertible perpetual preferred stock, shares issued		3,450,000		0	0
6.25% convertible perpetual preferred stock, shares issue Price per share (in dollars per share)		$ 100
6.25% convertible perpetual preferred stock, shares outstanding	172,129			0	0
Dividend on preferred stock per share Per annum (in dollars per share)		$ 6.25
Common Stock [Member]
Class of Stock [Line Items]
Common stock issued on conversion of preferred stock (in shares)	792,919		794,000

SHAREHOLDERS' EQUITY AND NONC73

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Common stock offering) (Details) - Common Stock [Member] - USD ($) $ / shares in Units, $ in Millions	Apr. 01, 2015	Mar. 31, 2015	Dec. 31, 2015
Shareholders' Equity And Noncontrolling Interest [Line Items]
Issuance of common stock (in shares)	2,000,000	35,000,000	37,000,000
Shares Issued, Price Per Share		$ 30
Issuance of common stock, net	$ 61	$ 1,000
Over-Allotment Option [Member]
Shareholders' Equity And Noncontrolling Interest [Line Items]
Period of option to purchase additional shares, days			30 days
Number of additional shares available for purchase			5,250,000

SHAREHOLDERS' EQUITY AND NONC74

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Equity incentive plan) (Details) $ / shares in Units, $ in Millions	Dec. 08, 2014shares	Dec. 31, 2015USD ($)item$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)$ / sharesshares
Share-based compensation disclosures [Line Items]
Stock compensation expense | $		$ 28	$ 23	$ 22
Stock Option [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee		600,000
Vesting (service) period		3 years
Awards Assumed in Kodiak Acquisition (in shares)		673,235	673,235
Unrecognized compensation cost | $		$ 0.1
Stock Appreciation Rights (SARs) [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee		600,000
Restricted stock [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee		300,000
Awards Assumed in Kodiak Acquisition (in shares)	47,325
Granted (in dollars per share) | $ / shares		$ 31.68	$ 32.41	$ 27.59
Unrecognized compensation cost | $		$ 21
Weighted average period over which cost will be recognized		1 year 9 months 18 days
Total fair value of restricted stock vested | $		$ 4	$ 31	$ 17
2013 Equity Plan [Member]
Share-based compensation disclosures [Line Items]
Number of shares authorized upon shareholder's approval		5,300,000
Increase in authorized shares	978,161
Number of options available for grant		4,108,863
Executive officers and employees [Member] | Restricted stock [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period		3 years
Minimum [Member] | Stock Option [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period		1 year
Minimum [Member] | Directors [Member] | Restricted stock [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period		1 year
Maximum [Member] | Stock Option [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period		3 years
Market-based vesting criteria [Member] | Executive officers [Member] | Restricted stock [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period		3 years
Granted (in shares)			750,681	751,872
Granted (in dollars per share) | $ / shares		$ 33.25	$ 26.59	$ 23.01
Market-based vesting criteria [Member] | Executive officers [Member] | 2013 Equity Plan [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period		3 years
Market-based vesting criteria [Member] | Executive officers [Member] | 2013 Equity Plan [Member] | Restricted stock [Member]
Share-based compensation disclosures [Line Items]
Granted (in shares)		391,773
Market-based vesting criteria [Member] | Minimum [Member] | Executive officers [Member] | 2013 Equity Plan [Member]
Share-based compensation disclosures [Line Items]
Possible multiplier of shares earned | item		0
Market-based vesting criteria [Member] | Maximum [Member] | Executive officers [Member] | 2013 Equity Plan [Member]
Share-based compensation disclosures [Line Items]
Possible multiplier of shares earned | item		2

SHAREHOLDERS' EQUITY AND NONC75

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Equity awards assumed in Kodiak acquisition) (Details) - USD ($) $ / shares in Units, $ in Thousands		Dec. 08, 2014	Dec. 31, 2015	Dec. 31, 2014
Kodiak [Member]
Business Acquisition [Line Items]
Shares exchanged per each share owned		0.177
Stock Option [Member]
Business Acquisition [Line Items]
Awards Assumed in Kodiak Acquisition (in shares)			673,235	673,235
Amount attributed to prior service rendered			$ 7,000
Remaining amount to be expensed over remaining service term			$ 1,000
Vesting (service) period (in years)			3 years
Stock Option [Member] | Maximum [Member]
Business Acquisition [Line Items]
Vesting (service) period (in years)			3 years
Stock Option [Member] | Minimum [Member]
Business Acquisition [Line Items]
Vesting (service) period (in years)			1 year
Stock Option [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Weighted average fair value, per share		$ 12.20
Common Stock [Member] | Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Awards Assumed in Kodiak Acquisition (in shares)		257,601
Common Stock [Member] | Restricted Stock Units (RSUs) [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Fair value of Whiting’s common stock issued	[1]	$ 9,596
Common Stock [Member] | Stock Option [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Fair value of Whiting’s common stock issued		$ 7,523
[1]	257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiak's 1,455,409 restricted stock units held by employees as of December 8, 2014.

SHAREHOLDERS' EQUITY AND NONC76

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Assumption for valuing market based restricted shares) (Details) - item	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Dividend yield (as a percent)	0.00%
Stock Option [Member] | Kodiak [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility (as a percent)	49.70%
Risk-free interest rate (as a percent)	1.90%
Expected term	6 years 1 month 6 days
Stock Option [Member] | Kodiak [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility (as a percent)	40.30%
Risk-free interest rate (as a percent)	0.08%
Expected term	2 years
Market-based vesting criteria [Member] | Executive officers [Member] | Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of simulations	2,500,000	65,000	65,000
Expected volatility (as a percent)	40.30%	42.30%	43.10%
Risk-free interest rate (as a percent)	0.99%	0.86%	0.41%
Dividend yield (as a percent)	0.00%	0.00%	0.00%

SHAREHOLDERS' EQUITY AND NONC77

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Summary of nonvested restricted stock) (Details) - Restricted stock [Member] - $ / shares		Dec. 08, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards Assumed in Kodiak Acquisition (in shares)		47,325
Balance at the beginning of the period (in dollars per share)			$ 31.16	$ 31.71	$ 37.02
Granted (in dollars per share)			31.68	32.41	27.59
Awards Assumed in Kodiak Acquisition (in dollars per share)	[1]			37.25
Vested (in dollars per share)			53.26	34.05	35.32
Forfeited (in dollars per share)			30.85	34.86	30.95
Balance at the end of the period (in dollars per share)			$ 30.03	$ 31.16	$ 31.71
Service-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in shares)			281,589	279,105	244,801
Granted (in shares)			824,412	157,175	188,920
Awards Assumed in Kodiak Acquisition (in shares)	[1]			304,926
Vested (in shares)			(148,838)	(442,584)	(139,353)
Forfeited (in shares)			(64,470)	(17,033)	(15,263)
Balance at the end of the period (in shares)			892,693	281,589	279,105
Market-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in shares)			1,175,279	1,165,205	706,225
Granted (in shares)			391,773	750,681	751,872
Vested (in shares)				(371,855)	(208,471)
Forfeited (in shares)			(166,089)	(368,752)	(84,421)
Balance at the end of the period (in shares)			1,400,963	1,175,279	1,165,205
[1]	Kodiak's existing restricted stock units and restricted stock awards held by employees, which automatically converted into 257,601 restricted stock units and 47,325 restricted stock awards of Whiting and vested upon closing of the Kodiak Acquisition.

SHAREHOLDERS' EQUITY AND NONC78

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Summary of stock options outstanding) (Details) - Stock Option [Member] - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in shares)	968,393	420,840	422,695
Options Assumed in Kodiak Acquisition (in shares)	673,235	673,235
Exercised (in shares)	(150,952)	(117,123)
Forfeited or expired (in shares)	(229,266)	(8,559)	(1,855)
Balance at the end of the period (in shares)	588,175	968,393	420,840
Options vested and expected to vest (in shares)	558,149
Options exercisable (in shares)	527,317
Balance at the beginning of the period (in dollars per share)	$ 41.09	$ 28.65	$ 28.79
Options Assumed in Kodiak Acquisition (in dollars per share)		44.48
Exercised (in dollars per share)	20.75	15.21
Forfeitures or expired (in dollars per share)	53.81	50.51	60.28
Balance at the end of the period (in dollars per share)	41.35	$ 41.09	$ 28.65
Options vested and expected to vest (in dollars per share)	40.84
Options exercisable (in dollars per share)	$ 39.30
Aggregate Intrinsic Value, options Exercised	$ 2,007,000	$ 6,203,000
Aggregate Intrinsic Value, options outstanding, end of period	45,000
Options vested and expected to vest, Aggregate Intrinsic Value	40,000
Options exercisable, Aggregate Intrinsic Value	$ 45,000
Weighted Average Remaining Contractual Term, options outstanding	5 years 6 months
Weighted Average Remaining Contractual Term, options vested and expected to vest	5 years 6 months
Weighted Average Remaining Contractual Term, options exercisable	5 years 3 months 18 days

SHAREHOLDERS' EQUITY AND NONC79

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Schedule of noncontrolling interest) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Noncontrolling Interest disclosures [Line Items]
Balance at the beginning of the period	$ 8,070	$ 8,132
Net income (loss)	(86)	(62)	$ (52)
Balance at the end of the period	$ 7,984	$ 8,070	$ 8,132
Sustainable Water Resources, LLC [Member]
Noncontrolling Interest disclosures [Line Items]
Third party ownership interest (as a percent)	25.00%

SHAREHOLDERS' EQUITY AND NONC80

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Rights Agreement) (Details)	Feb. 22, 2011	Dec. 31, 2015item / shares$ / sharesshares	Dec. 31, 2006shares
Rights [Member]
Class of Warrant or Right [Line Items]
Price of one hundredth of a share, Series A Junior Participating Preferred Stock		$ 180
Redemption price per share, Series A Junior Participating Preferred Stock		$ 0.001
Common Stock [Member]
Class of Warrant or Right [Line Items]
Number of preferred share purchase rights declared as a dividend on a common stock | shares			1
Stock split approved	2
Number of rights outstanding per common share | item / shares		0.50
Minimum percentage ownership for preferred rights price to apply		15.00%
Series A Junior Participating Preferred Stock [Member]
Class of Warrant or Right [Line Items]
Junior Participating Preferred Stock par value		$ 0.001
Series A Junior Participating Preferred Stock [Member] | Rights [Member]
Class of Warrant or Right [Line Items]
Number of securities into which each warrant or right may be converted | shares		0.01

INCOME TAXES (Narrative) (Detai

INCOME TAXES (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
U.S. statutory income tax rate (as a percent)	35.00%	35.00%	35.00%
EOR credit carryforwards	$ 7,946	$ 7,946
Alternative minimum tax credit carryforwards	15,694	15,694
Valuation allowance	5,061	5,638
Amount of temporary differences	729,000
Current deferred income taxes		48,000
Unrecognized tax benefit	170	170	$ 170
Unrecognized tax benefits, penalties and interest expense	0	0	0
Unrecognized tax benefits, penalties and interest accrued	0
Income Tax Expense (Benefit)	(774,227)	$ 79,170	$ 205,868
Kodiak [Member]
Operating Loss Carryforwards [Line Items]
Federal operating loss carryforwards	72,000
Federal [Member]
Operating Loss Carryforwards [Line Items]
Federal operating loss carryforwards	2,300,000
Net operating loss carryforwards related to tax deductions that deviate from compensation expense	$ 70,000

INCOME TAXES (Schedule of incom

INCOME TAXES (Schedule of income expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
INCOME TAXES [Abstract]
Federal		$ (2,758)	$ 7,060
State	$ (357)	5,383	(6,074)
Total current income tax expense (benefit)	(357)	2,625	986
Federal	(736,520)	65,522	196,787
State	(37,350)	11,023	8,095
Total deferred income tax expense (benefit)	(773,870)	76,545	204,882
Total income tax expense (benefit)	$ (774,227)	$ 79,170	$ 205,868

INCOME TAXES (Reconciliation of

INCOME TAXES (Reconciliation of statutory income tax expense to income expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
INCOME TAXES [Abstract]
U.S. statutory income tax rate (as a percent)	35.00%	35.00%	35.00%
U.S. statutory income tax expense (benefit)	$ (1,047,723)	$ 50,371	$ 200,155
State income taxes, net of federal benefit	(44,654)	12,705	13,962
State income tax credits			(10,525)
Statutory depletion	(327)	(618)	(796)
Enacted changes in state tax laws	7,350	3,700	(1,416)
Market-based equity awards	2,690	2,805
Permanent items	5,071	3,504	2,122
Transaction costs		6,936
Goodwill impairment	305,820
Other	(2,454)	(233)	2,366
Total income tax expense (benefit)	$ (774,227)	$ 79,170	$ 205,868

INCOME TAXES (Components of def

INCOME TAXES (Components of deferred income tax assets and liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
INCOME TAXES [Abstract]
Net operating loss carryforward	$ 835,995	$ 588,330
Production Participation Plan Liability		26,942
Asset retirement obligations	18,896	13,791
Underwriter fees	6,060	14,065
Restricted stock compensation	17,675	15,527
Premium on senior notes		7,979
EOR credit carryforwards	7,946	7,946
Alternative minimum tax credit carryforwards	15,694	15,694
Transaction costs	6,395	7,957
Other	11,110	9,493
Total deferred income tax assets	919,771	707,724
Less valuation allowances	(5,061)	(5,638)
Net deferred income tax assets	914,710	702,086
Oil and gas properties	1,264,598	1,785,926
Trust distributions	101,665	129,437
Discount on convertible senior notes	76,475
Derivative instruments	65,764	64,898
Total deferred income tax liabilities	1,508,502	1,980,261
Total net deferred income tax liabilities	$ 593,792	$ 1,278,175

EARNINGS PER SHARE (Narrative)

EARNINGS PER SHARE (Narrative) (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted stock [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Antidilutive securities excluded from computation of earnings per share	516,139
Stock options excluded from earnings per share calculation (in shares)		803,902	173,778
Restricted stock excluded from earnings per share calculation (in shares)	676,277
Stock options [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Antidilutive securities excluded from computation of earnings per share	85,564
Stock options excluded from earnings per share calculation (in shares)	514,757
Restricted stock excluded from earnings per share calculation (in shares)		791	8,689

EARNINGS PER SHARE (Reconciliat

EARNINGS PER SHARE (Reconciliation between basic and diluted earnings per share)(Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Numerator:
Net income (loss) available to shareholders										$ (2,219,182)	$ 64,807	$ 366,055
Preferred stock dividends	[1]											(494)
Net income (loss) available to common shareholders, basic										$ (2,219,182)	$ 64,807	$ 365,561
Denominator:
Weighted average shares outstanding, basic										195,472	122,138	118,260
Numerator:
Preferred stock dividends												$ 538
Adjusted net income (loss) available to common shareholders, diluted										$ (2,219,182)	$ 64,807	$ 366,099
Denominator:
Weighted average shares outstanding, basic										195,472	122,138	118,260
Restricted stock and stock options (in shares)											381	957
Convertible perpetual preferred stock (in shares)												371
Weighted average shares outstanding, diluted										195,472	122,519	119,588
Earnings (loss) per common share, basic (in dollars per share)		$ (0.48)	$ (9.14)	$ (0.73)	$ (0.63)	$ (2.69)	$ 1.33	$ 1.27	$ 0.92	$ (11.35)	$ 0.53	$ 3.09
Earnings (loss) per common share, diluted (in dollars per share)		$ (0.48)	$ (9.14)	$ (0.73)	$ (0.63)	$ (2.68)	$ 1.32	$ 1.26	$ 0.91	$ (11.35)	$ 0.53	$ 3.06
Decrease in accumulated preferred stock dividends										$ 0	$ 0	$ 40
[1]	For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated. There were no accumulated dividend adjustments for the years ended December 31, 2015 or 2014.For the year ended December 31, 2015,

RELATED PARTY TRANSACTIONS (Nar

RELATED PARTY TRANSACTIONS (Narrative) (Details) $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)itemshares	Dec. 31, 2014	Dec. 31, 2013USD ($)
Whiting USA Trust I [Member]
Related Party Transaction [Line Items]
Percentage of ownership in subsidiary		15.80%	15.80%
Whiting's ownership interest (in units) | shares		2,186,389
Payments of unit distributions, net of state tax withholdings		$ 5
Distributions back from the trust		$ 1
Alliant Energy Corporation [Member]
Related Party Transaction [Line Items]
Percentage of tax benefits due to affiliate related to step-up of tax basis assets			90.00%
Payments under agreement	$ 26			$ 2
Interest expense	$ 3			$ 3
Working interest in offshore platforms (as a percent)		6.00%
Number of offshore platforms in California that the Company has working interest in | item		3

RELATED PARTY TRANSACTIONS (Sum

RELATED PARTY TRANSACTIONS (Summary of related party receivable and payable balances) (Details) - Whiting USA Trust I [Member] - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Unit distributions due from Trust I	[1]		$ 652
Unit distributions payable to Trust I	[2]		$ 4,133
Percentage of ownership in subsidiary		15.80%	15.80%
[1]	This amount represented Whiting's 15.8% interest in the net proceeds due from Trust I and was included within accounts receivable trade, net in the Company's consolidated balance sheet.
[2]	This amount represented net proceeds from Trust I's underlying properties that the Company had received between the last Trust I distribution date and December 31, 2014, but which the Company had not yet distributed to Trust I as of December 31, 2014. This amount was included within accounts payable trade in the Company's consolidated balance sheet as of December 31, 2014. Due to processing of Trust I revenues and expenses after December 31, 2014, the amount of Whiting's actual distribution to Trust I, and the related distribution by Trust I to its unitholders, during the year ended December 31, 2015 was $5 million, net of state tax withholdings, and the Company received $1 million in distributions back from Trust I pursuant to its retained ownership in 2,186,389 Trust I units.

COMMITMENTS AND CONTINGENCIES89

COMMITMENTS AND CONTINGENCIES (Narrative) (Details) $ in Thousands	2 Months Ended	12 Months Ended
	Feb. 25, 2016USD ($)item	Dec. 31, 2015USD ($)ft²contractitemMBbls	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Rental expense		$ 9,000	$ 7,000	$ 5,000
Ship-Or-Pay Arrangements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of Ship or pay agreements | contract		3
Number of suppliers | contract		2
Future commitments under purchase agreements		$ 74,000
Crude oil [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Delivery commitments for year 2016 | MBbls		15,600
Delivery commitments for year 2017 | MBbls		25,100
Delivery commitments for year 2018 | MBbls		26,900
Delivery commitments for year 2019 | MBbls		28,800
Delivery commitments for year 2020 | MBbls		11,500
Delivery commitments for year 2021 | MBbls		5,500
Delivery commitments for year 2022 | MBbls		5,500
Delivery commitments for year 2023 | MBbls		4,100
Delivery commitments deficiency payments		$ 15,000
Take-Or-Pay Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of take or pay purchase agreements | contract		3
Payments under purchase contracts		$ 88,000	105,000	84,000
Future commitments under purchase agreements		$ 107,000
Pipeline Transportation Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of pipeline transportation agreements | contract		2
Number of suppliers | item		1
Future commitments under purchase agreements		$ 49,063
Natural Gas, CO2 And Water Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Payments under purchase contracts		15,000	13,000	4,000
Future commitments under purchase agreements		123,000
Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Payments under purchase contracts		$ 161,000	$ 106,000	$ 93,000
Number of contracts with drilling rig companies | contract		7
Future commitments under purchase agreements		$ 95,634
Drilling Rig Contracts [Member] | Subsequent Event [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts with drilling rig companies terminated early | item	3
Termination penalties	$ 24,000
Water Disposal Agreement [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Estimated minimum future commitments under water disposal agreement		$ 146,000
December 2017 Expiration [Member] | Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts with drilling rig companies | contract		4
Termination penalties		$ 55,000
Expiration 2016 [Member] | Take-Or-Pay Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of take or pay purchase agreements | contract		1
Expiration 2017 [Member] | Ship-Or-Pay Arrangements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of Ship or pay agreements | contract		1
Expiration 2017 [Member] | Take-Or-Pay Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of take or pay purchase agreements | contract		1
Expiration 2020 [Member] | Take-Or-Pay Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of take or pay purchase agreements | contract		1
Expiration 2026 [Member] | Ship-Or-Pay Arrangements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of Ship or pay agreements | contract		2
Denver, Colorado office [Member] | Expiration 2016 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²		36,300
Denver, Colorado office [Member] | Expiration 2019 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²		204,000
Dickinson, North Dakota office [Member] | Expiration 2016 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²		20,000
Midland, Texas office [Member] | Expiration 2020 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²		47,900
Mountrail County, North Dakota [Member] | Crude oil [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of delivery commitments | item		1
Weld County, Colorado [Member] | Crude oil [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of delivery commitments | item		2

COMMITMENTS AND CONTINGENCIES90

COMMITMENTS AND CONTINGENCIES (Minimum future payments under non-cancelable operating leases and unconditional purchase obligations) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	$ 83,199
2,017	37,600
2,018	12,062
2,019	11,213
2,020	5,585
Thereafter	22,218
Total	171,877
Non-Cancelable Leases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	7,710
2,017	6,717
2,018	6,693
2,019	5,844
2,020	216
Total	27,180
Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	70,120
2,017	25,514
Total	95,634
Pipeline Transportation Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	5,369
2,017	5,369
2,018	5,369
2,019	5,369
2,020	5,369
Thereafter	22,218
Total	$ 49,063

OIL AND GAS ACTIVITIES (Schedul

OIL AND GAS ACTIVITIES (Schedule of cost Incurred in oil and gas producing activities) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 08, 2014
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development	[1]	$ 2,137,755	$ 2,891,893	$ 2,132,824
Proved property acquisition	[2]		2,278,855	232,572
Unproved property acquisition	[2]	29,050	1,035,439	174,103
Exploration		192,422	216,587	363,234
Total		2,359,227	6,422,774	2,902,733
Addition to Oil and Gas Properties for Asset Retirement Costs related to new wells drilled or acquired		48,000	45,000	$ 30,000
Proved properties		12,709,257	12,956,834
Unproved leasehold costs		$ 689,754	$ 1,232,040
Kodiak [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved properties					$ 2,266,607
Unproved leasehold costs					$ 1,000,396
[1]	During 2015, 2014 and 2013, non-cash additions to oil and gas properties of $48 million, $45 million and $30 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company's oil and gas wells, are included in development costs in the table above.
[2]	During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property additions related to the Kodiak Acquisition.

OIL AND GAS ACTIVITIES (Net cap

OIL AND GAS ACTIVITIES (Net capitalized costs related to the Company’s oil and gas producing activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
OIL AND GAS ACTIVITIES [Abstract]
Proved oil and gas properties	$ 12,709,257	$ 12,956,834
Unproved oil and gas properties	1,195,268	1,992,868
Accumulated depletion	(3,279,156)	(3,003,270)
Oil and gas properties, net	$ 10,625,369	$ 11,946,432

OIL AND GAS ACTIVITIES (Net cha

OIL AND GAS ACTIVITIES (Net changes in capitalized exploratory well costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OIL AND GAS ACTIVITIES [Abstract]
Balance at the beginning of the period	$ 14,293	$ 85,378	$ 108,861
Additions to capitalized exploratory well costs pending the determination of proved reserves	54,707	145,336	281,951
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(63,352)	(200,869)	(291,962)
Capitalized exploratory well costs charged to expense	(5,648)	(15,552)	(13,472)
Balance at the end of the period		$ 14,293	$ 85,378
Capitalized exploratory cost for exploratory wells in progress	$ 0

DISCLOSURES ABOUT OIL AND GAS94

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended					252 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 1995	Dec. 31, 1994	Dec. 31, 2015
Percentage of proved reserve quantities and related future cash flows reviewed by independent petroleum engineers	100.00%					100.00%
Increase (Decrease) in undiscounted future cash flow if hedging impact considered	$ (71)	$ (7)	$ 0
Maximum [Member]
Percentage of overriding royalty interest allocated					3.00%
Percentage of oil and gas sales less lease operating expenses and production taxes allocated		5.00%		5.00%		5.00%
Minimum [Member]
Percentage of overriding royalty interest allocated					2.00%
Percentage of oil and gas sales less lease operating expenses and production taxes allocated		1.75%		1.75%		1.75%

DISCLOSURES ABOUT OIL AND GAS95

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Summary of changes in quantities of proved oil and gas reserve) (Details)	12 Months Ended
	Dec. 31, 2015MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls	Dec. 31, 2013MBoeMMcfMBbls	Dec. 31, 2012MBoeMMcfMBbls
Reserve Quantities [Line Items]
Beginning balance of proved oil and gas reserve | MBoe	780,316	438,542	378,760
Extensions and discoveries | MBoe	189,304	174,811	108,772
Sales of minerals in place | MBoe	(53,156)	(2,130)	(43,838)
Purchase of minerals in place | MBoe		195,609	17,146
Production | MBoe	(59,570)	(41,804)	(34,342)
Revisions to previous estimates | MBoe	(36,327)	15,288	12,044
Ending balance of proved oil and gas reserves | MBoe	820,567	780,316	438,542
Proved developed reserves | MBoe	403,986	412,234	252,446	241,864
Proved undeveloped reserves | MBoe	416,581	368,082	186,096	136,896
Oil [Member]
Reserve Quantities [Line Items]
Beginning balance of proved oil and gas reserve	643,629	347,421	301,285
Extensions and discoveries	131,134	146,122	88,293
Sales of minerals in place	(33,767)	(1,642)	(36,992)
Purchases of minerals in place		169,586	14,543
Production	(47,176)	(33,485)	(27,035)
Revisions to previous estimates	(97,143)	15,627	7,327
Ending balance of proved oil and gas reserves	596,677	643,629	347,421
Proved developed reserves	298,444	333,593	198,204	190,845
Proved undeveloped reserves	298,233	310,036	149,217	110,440
NGLs [Member]
Reserve Quantities [Line Items]
Beginning balance of proved oil and gas reserve	54,684	44,869	40,098
Extensions and discoveries	26,074	12,947	9,830
Sales of minerals in place	(3,240)		(4,777)
Purchases of minerals in place			1,311
Production	(5,539)	(3,283)	(2,821)
Revisions to previous estimates	40,968	151	1,228
Ending balance of proved oil and gas reserves	112,947	54,684	44,869
Proved developed reserves	55,437	28,935	23,721	24,204
Proved undeveloped reserves	57,510	25,749	21,148	15,894
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning balance of proved oil and gas reserve | MMcf	492,020	277,514	224,264
Extensions and discoveries | MMcf	192,575	94,452	63,893
Sales of minerals in place | MMcf	(96,891)	(2,925)	(12,411)
Purchases of minerals in place | MMcf		156,140	7,751
Production | MMcf	(41,129)	(30,218)	(26,917)
Revisions to previous estimates | MMcf	119,085	(2,943)	20,934
Ending balance of proved oil and gas reserves | MMcf	665,660	492,020	277,514
Proved developed reserves | MMcf	300,631	298,237	183,129	160,893
Proved undeveloped reserves | MMcf	365,029	193,783	94,385	63,371

DISCLOSURES ABOUT OIL AND GAS96

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Summary of changes in quantities of proved oil and gas reserve-Narrative) (Details)	12 Months Ended
	Dec. 31, 2015itemMBoe	Dec. 31, 2014itemMBoe	Dec. 31, 2013itemMBoe	Dec. 08, 2014item	Sep. 20, 2013item
Reserve Quantities [Line Items]
Extensions and discoveries | MBoe	189,304	174,811	108,772
Sales of minerals in place | MBoe	53,156	2,130	43,838
Purchase of minerals in place | MBoe		195,609	17,146
Revisions to previous estimates | MBoe	(36,327)	15,288	12,044
Revisions to estimated caused by higher crude oil prices incorporated into the Company's reserve estimates | item	82,300	15,600	4,900
Revisions to estimated attributable to reservoir analysis and well performance | item	46,000	300	7,100
Williston Basin [Member]
Reserve Quantities [Line Items]
Number of wells acquired | item					121
Kodiak [Member]
Reserve Quantities [Line Items]
Number of wells acquired | item				778

DISCLOSURES ABOUT OIL AND GAS97

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract]
Future cash flows	$ 29,339,528	$ 59,949,707	$ 35,178,399
Future production costs	(12,344,463)	(20,772,234)	(12,973,292)
Future development costs	(6,166,397)	(7,924,573)	(5,355,383)
Future income tax expense	(388,072)	(8,579,237)	(3,954,401)
Future net cash flows	10,440,596	22,673,663	12,895,323
10% annual discount for estimated timing of cash flows	(5,866,225)	(11,830,243)	(6,301,462)
Standardized measure of discounted future net cash flows	$ 4,574,371	$ 10,843,420	$ 6,593,861	$ 5,407,033

DISCLOSURES ABOUT OIL AND GAS98

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract]
Beginning of year	$ 10,843,420	$ 6,593,861	$ 5,407,033
Sale of oil and gas produced, net of production costs	(1,354,054)	(2,274,682)	(2,010,925)
Sales of minerals in place	(1,414,511)	(48,532)	(1,064,195)
Net changes in prices and production costs	(11,001,949)	81,522	902,916
Extensions, discoveries and improved recoveries	2,078,071	3,950,413	2,827,321
Previously estimated development costs incurred during the period	1,625,160	1,149,926	832,096
Changes in estimated future development costs	102,499	(3,382,849)	(1,264,189)
Purchases of minerals in place		4,420,417	445,669
Revisions of previous quantity estimates	(966,713)	345,775	313,069
Net change in income taxes	3,578,106	(651,817)	(335,637)
Accretion of discount	1,084,342	659,386	540,703
End of year	$ 4,574,371	$ 10,843,420	$ 6,593,861

DISCLOSURES ABOUT OIL AND GAS99

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves calculating average sales prices) (Details)	12 Months Ended
	Dec. 31, 2015$ / bbl$ / Mcf	Dec. 31, 2014$ / bbl$ / Mcf	Dec. 31, 2013$ / bbl$ / Mcf
Oil (per Bbl) [Member]
Weighted Average Sales Price [Line Items]
Weighted average sales price	43.07	84.69	90.80
NGLs (per Bbl) [Member]
Weighted Average Sales Price [Line Items]
Weighted average sales price	15.53	46.59	54.38
Natural Gas (per Mcf) [Member]
Weighted Average Sales Price [Line Items]
Weighted average sales price | $ / Mcf	2.83	5.88	4.30

QUARTERLY FINANCIAL DATA (Detai

QUARTERLY FINANCIAL DATA (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
QUARTERLY FINANCIAL DATA [Abstract]
Oil, NGL and natural gas sales		$ 417,952	$ 504,155	$ 650,527	$ 519,848	$ 672,553	$ 805,054	$ 825,760	$ 721,250	$ 2,092,482	$ 3,024,617	$ 2,666,549
Operating profit (loss)	[1]	(60,966)	18,130	128,012	25,586	177,722	326,215	370,033	311,169
Net income (loss)		$ (98,727)	$ (1,865,118)	$ (149,295)	$ (106,128)	$ (353,693)	$ 157,961	$ 151,426	$ 109,051	$ (2,219,268)	$ 64,745	$ 366,003
Basic (in dollars per share)		$ (0.48)	$ (9.14)	$ (0.73)	$ (0.63)	$ (2.69)	$ 1.33	$ 1.27	$ 0.92	$ (11.35)	$ 0.53	$ 3.09
Diluted (in dollars per share)		$ (0.48)	$ (9.14)	$ (0.73)	$ (0.63)	$ (2.68)	$ 1.32	$ 1.26	$ 0.91	$ (11.35)	$ 0.53	$ 3.06
[1]	Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.