Chord Energy (WLLBW) 10-K 22 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 15, 2018	Jun. 30, 2017
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, 2017
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		90,927,193
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Public Float			$ 2,002,000,000
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents		$ 879,379	$ 55,975
Restricted cash			17,250
Accounts receivable trade, net		284,214	173,919
Prepaid expenses and other		26,035	26,312
Assets held for sale			349,146
Total current assets		1,189,628	622,602
Property and equipment:
Oil and gas properties, successful efforts method		11,293,650	13,230,851
Other property and equipment		134,524	134,638
Total property and equipment		11,428,174	13,365,489
Less accumulated depreciation, depletion and amortization		(4,244,735)	(4,222,071)
Total property and equipment, net		7,183,439	9,143,418
Other long-term assets		29,967	110,122
TOTAL ASSETS		8,403,034	9,876,142
Current liabilities:
Current portion of long-term debt		958,713
Accounts payable trade		32,761	32,126
Revenues and royalties payable		171,028	147,226
Accrued capital expenditures		69,744	56,830
Accrued interest		40,971	44,749
Accrued lease operating expenses		36,865	45,015
Accrued liabilities and other		51,590	63,538
Taxes payable		28,771	39,547
Derivative liabilities		132,525	17,628
Accrued employee compensation and benefits		30,360	31,134
Liabilities related to assets held for sale			538
Total current liabilities		1,553,328	478,331
Long-term debt		2,764,716	3,535,303
Deferred income taxes			475,689
Asset retirement obligations		129,206	168,504
Other long-term liabilities		36,642	69,123
Total liabilities		4,483,892	4,726,950
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 225,000,000 shares authorized; 92,094,837 issued and 90,698,889 outstanding as of December 31, 2017 and 91,793,472 issued and 90,503,482 outstanding as of December 31, 2016	[1]	92	367
Additional paid-in capital		6,405,490	6,389,435
Accumulated deficit		(2,486,440)	(1,248,572)
Total Whiting shareholders' equity		3,919,142	5,141,230
Noncontrolling interest			7,962
Total equity		3,919,142	5,149,192
TOTAL LIABILITIES AND EQUITY		$ 8,403,034	$ 9,876,142
[1]	All share amounts (except par value amounts) as of December 31, 2016 have been retroactively adjusted to reflect the Company's one-for-four reverse stock split in November 2017, as described in Note 8 to these consolidated financial statements.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2017$ / sharesshares	Dec. 31, 2016$ / sharesshares
CONSOLIDATED BALANCE SHEETS [Abstract]
Common stock, par value (in dollars per share) | $ / shares	$ 0.001	$ 0.001
Common stock, shares authorized	225,000,000	600,000,000
Common stock, shares issued	92,094,837	91,793,472
Common stock, shares outstanding	90,698,889	90,503,482

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING REVENUES
Oil, NGL and natural gas sales		$ 1,481,435	$ 1,284,982	$ 2,092,482
OPERATING EXPENSES
Lease operating expenses		366,880	395,135	555,392
Production taxes		123,483	108,715	183,035
Depreciation, depletion and amortization		948,939	1,171,582	1,243,293
Exploration and impairment		936,177	121,468	1,881,671
Goodwill impairment				873,772
General and administrative		124,288	146,878	172,616
Derivative (gain) loss, net		122,847	(587)	(217,972)
Loss on sale of properties		401,113	184,567	60,791
Amortization of deferred gain on sale		(12,963)	(14,570)	(16,751)
Total operating expenses		3,010,764	2,113,188	4,735,847
LOSS FROM OPERATIONS		(1,529,329)	(828,206)	(2,643,365)
OTHER INCOME (EXPENSE)
Interest expense		(191,088)	(557,620)	(334,125)
Gain (loss) on extinguishment of debt		(1,540)	(42,236)	(18,361)
Interest income and other		1,316	1,292	2,356
Total other expense		(191,312)	(598,564)	(350,130)
LOSS BEFORE INCOME TAXES		(1,720,641)	(1,426,770)	(2,993,495)
INCOME TAX BENEFIT
Current		(7,291)	(7,190)	(357)
Deferred		(475,688)	(80,456)	(773,870)
Total income tax benefit		(482,979)	(87,646)	(774,227)
NET LOSS		(1,237,662)	(1,339,124)	(2,219,268)
Net loss attributable to noncontrolling interests		14	22	86
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS		$ (1,237,648)	$ (1,339,102)	$ (2,219,182)
LOSS PER COMMON SHARE
Basic (in dollars per share)	[1]	$ (13.65)	$ (21.27)	$ (45.41)
Diluted (in dollars per share)	[1]	$ (13.65)	$ (21.27)	$ (45.41)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic (in shares)	[1]	90,683	62,967	48,868
Diluted (in shares)	[1]	90,683	62,967	48,868
[1]	All share and per share amounts have been retroactively adjusted for the 2015 and 2016 periods to reflect the Company's one-for-four reverse stock split in November 2017, as described in Note 8 to these consolidated financial statements.

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical)	Nov. 08, 2017	Nov. 30, 2017
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Reverse stock split ratio	0.25	0.25

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$ (1,237,662)	$ (1,339,124)	$ (2,219,268)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	948,939	1,171,582	1,243,293
Deferred income tax benefit	(475,688)	(80,456)	(773,870)
Amortization of debt issuance costs, debt discount and debt premium	31,715	335,569	46,525
Stock-based compensation	21,641	25,647	28,098
Amortization of deferred gain on sale	(12,963)	(14,570)	(16,751)
Loss on sale of properties	401,113	184,567	60,791
Undeveloped leasehold and oil and gas property impairments	899,853	75,622	1,738,308
Goodwill impairment			873,772
Exploratory dry hole costs		134	9,440
Loss on extinguishment of debt	1,540	42,236	18,361
Non-cash derivative (gain) loss	131,129	151,151	(1,615)
Other, net	(9,255)	(10,185)	(9,337)
Changes in current assets and liabilities:
Accounts receivable trade, net	(110,879)	155,416	207,367
Prepaid expenses and other	(444)	586	54,027
Accounts payable trade and accrued liabilities	(24,953)	(62,774)	(117,136)
Revenues and royalties payable	23,799	(32,185)	(74,417)
Taxes payable	(10,776)	(8,206)	(16,196)
Net cash provided by operating activities	577,109	595,010	1,051,392
CASH FLOWS FROM INVESTING ACTIVITIES
Drilling and development capital expenditures	(830,552)	(539,208)	(2,455,218)
Acquisition of oil and gas properties	(21,429)	(4,718)	(28,449)
Other property and equipment	(4,596)	(9,255)	(13,266)
Proceeds from sale of oil and gas properties	929,974	313,355	514,814
Deposit received on properties held for sale		17,250
Net cash provided by (used in) investing activities	73,397	(222,576)	(1,982,119)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit agreement	1,900,000	1,310,000	3,550,000
Repayments of borrowings under credit agreement	(2,450,000)	(1,560,000)	(4,150,000)
Issuance of common stock			1,111,148
Issuance of 1.25% Convertible Senior Notes due 2020			1,250,000
Redemption of 6.5% Senior Subordinated Notes due 2018	(275,121)
Early conversion payments for New Convertible Notes		(41,919)
Debt and equity issuance costs	(13,150)	(22,499)	(54,461)
Proceeds from stock options exercised			3,048
Restricted stock used for tax withholdings	(6,081)	(844)	(1,126)
Net cash provided by (used in) financing activities	155,648	(315,262)	868,680
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	806,154	57,172	(62,047)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Beginning of period	73,225	16,053	78,100
End of period	879,379	73,225	16,053
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Income taxes paid (refunded), net	49	(1,044)	(604)
Interest paid, net of amounts capitalized	163,151	239,963	292,582
NONCASH INVESTING ACTIVITIES
Accrued capital expenditures and accounts payable related to property additions	80,762	$ 65,052	94,105
Senior Notes [Member] | 6.625% Senior Notes due 2026 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Senior Notes	$ 1,000,000
Senior Notes [Member] | 6.25% Senior Notes due 2023 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Senior Notes			750,000
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 2021 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES
Redemption of Senior Notes			(353,500)
Senior Notes [Member] | 5.5% Senior Notes due 2022 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES
Redemption of Senior Notes			$ (404,000)

CONSOLIDATED STATEMENTS OF CAS7

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 08, 2014	Sep. 30, 2010
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes [Member]
Interest Rate (as a percent)	1.25%	1.25%	1.25%	1.25%
6.625% Senior Notes due 2026 [Member] | Senior Notes [Member]
Interest Rate (as a percent)	6.625%
6.25% Senior Notes due 2023 [Member] | Senior Notes [Member]
Interest Rate (as a percent)	6.25%	6.25%	6.25%	6.25%
6.5% Senior Subordinated Notes due 2018 [Member] | Senior Subordinated Notes [Member]
Interest Rate (as a percent)	6.50%	6.50%				6.50%
8.125% Senior Notes due 2019 [Member] | Senior Notes [Member]
Interest Rate (as a percent)			8.125%		8.125%
5.5% Senior Notes due 2021 [Member] | Senior Notes [Member]
Interest Rate (as a percent)			5.50%		5.50%
5.5% Senior Notes due 2022 [Member] | Senior Notes [Member]
Interest Rate (as a percent)			5.50%		5.50%

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Thousands, $ in Thousands		Mandatory Convertible Notes [Member]Additional Paid-in Capital [Member]	Mandatory Convertible Notes [Member]Total Whiting Shareholders' Equity [Member]	Mandatory Convertible Notes [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]	Total Whiting Shareholders' Equity [Member]	Noncontrolling Interest [Member]	Total
BALANCES at Dec. 31, 2014					$ 168	$ 3,385,094	$ 2,309,712	$ 5,694,974	$ 8,070	$ 5,703,044
BALANCES (in shares) at Dec. 31, 2014	[1]				42,087
Increase (Decrease) in Shareholders' Equity
Net loss							(2,219,182)	(2,219,182)	(86)	(2,219,268)
Issuance of common stock					$ 37	1,100,000		1,100,037		1,100,037
Issuance of common stock (in shares)	[1]				9,250
Equity component of 2020 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)	[1]				37
Restricted stock issued					$ 1	(1)
Restricted stock issued (in shares)	[1]				304
Restricted stock forfeited (in shares)	[1]				(58)
Restricted stock used for tax withholdings						(1,126)		(1,126)		(1,126)
Restricted stock used for tax withholdings (in shares)	[1]				(10)
Stock-based compensation						28,098		28,098		28,098
BALANCES at Dec. 31, 2015					$ 206	4,659,868	90,530	4,750,604	7,984	4,758,588
BALANCES (in shares) at Dec. 31, 2015	[1]				51,610
Increase (Decrease) in Shareholders' Equity
Net loss							(1,339,102)	(1,339,102)	(22)	(1,339,124)
Issuance of common stock upon conversion of convertible notes					$ 158	1,535,296		1,535,454		1,535,454
Issuance of common stock upon conversion of convertible notes, (in shares)	[1]				39,386
Reduction of equity component of 2020 Convertible Senior Notes upon extinguishment, net						(63,330)		(63,330)		(63,330)
Recognition of beneficial conversion features on convertible notes		$ 232,801	$ 232,801	$ 232,801
Restricted stock issued					$ 4	(4)
Restricted stock issued (in shares)	[1]				1,005
Restricted stock forfeited					$ (1)	1
Restricted stock forfeited (in shares)	[1]				(182)
Restricted stock used for tax withholdings						(844)		(844)		(844)
Restricted stock used for tax withholdings (in shares)	[1]				(26)
Stock-based compensation						25,647		25,647		25,647
BALANCES at Dec. 31, 2016					$ 367	6,389,435	(1,248,572)	5,141,230	7,962	5,149,192
BALANCES (in shares) at Dec. 31, 2016	[1]				91,793
Increase (Decrease) in Shareholders' Equity
Net loss							(1,237,648)	(1,237,648)	(14)	(1,237,662)
Conveyance of third party ownership interest in Sustainable Water Resources, LLC									$ (7,948)	(7,948)
Reverse stock split					$ (276)	276
Restricted stock issued					$ 2	(2)
Restricted stock issued (in shares)	[1]				707
Restricted stock forfeited					$ (1)	1
Restricted stock forfeited (in shares)	[1]				(261)
Restricted stock used for tax withholdings						(6,081)		(6,081)		(6,081)
Restricted stock used for tax withholdings (in shares)	[1]				(144)
Stock-based compensation						21,641		21,641		21,641
BALANCES at Dec. 31, 2017					$ 92	6,405,490	(2,486,440)	$ 3,919,142		$ 3,919,142
BALANCES (in shares) at Dec. 31, 2017	[1]				92,095
Increase (Decrease) in Shareholders' Equity
Cumulative effect of change in accounting principle						$ 220	$ (220)
[1]	All common share amounts have been retroactively adjusted for the 2015 and 2016 periods to reflect the Company's one-for-four reverse stock split in November 2017, as described in Note 8 to these consolidated financial statements.

CONSOLIDATED STATEMENTS OF EQU9

CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical)	Nov. 08, 2017	Nov. 30, 2017
CONSOLIDATED STATEMENTS OF EQUITY [Abstract]
Reverse stock split ratio	0.25	0.25

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2017
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, production, acquisition and exploration of crude oil, NGLs and natural gas primarily in the Rocky Mountains region 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 and Whiting Programs, Inc. Basis of Presentation of Consolidated Financial Statements —The consolidated financial statements have been prepared in accordance with GAAP and SEC rules and regulations and 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 GAAP 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 (i) oil and natural gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with business combinations, including the determination of any resulting goodwill; (vi) valuations of the Company’s reporting unit used in impairment tests of goodwill; (vii) income taxes; (viii) accrued liabilities; (ix) valuation of derivative instruments; and (x) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates. 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. Cash, Cash Equivalents and Restricted Cash —Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less. Restricted cash at December 31, 2016 relate d to a deposit received in connection with the sale of Whiting’s interests in the Robinson Lake and Belfield gas processing plants. The use of these funds was restricted per the terms of the purchase agreement until the sale transaction closed on January 1, 2017. Refer to the “Acquisition and Divestitures” footnote for further information on this transaction. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and the consolidated statements of cash flows:     December 31,  2017 2016  Cash and cash equivalents $ 879,379 $ 55,975  Restricted cash - 17,250  Total cash, cash equivalents and restricted cash $ 879,379 $ 73,225 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, 2017 and 2016, the Company had an allowance for doubtful accounts of $17 million and $10 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 and totaled $24 million and $33 million as of December 31, 2017 and 2016, respectively. Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or net realizable value. Oil in tanks is included in prepaid expenses and other and totaled $7 million and $8 million as of December 31, 2017 and 2016, respectively. 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 totaled $83 5 m illion and $1.6 billion for the year s ended December 31, 201 7 and 2015, respectively , which 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 2017, 2016 and 2015, the Company capitalized interest of $0.1 million, $0.1 million and $4 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 totaled $59 million, $73 million and $135 million for the years ended December 31, 2017, 2016 and 2015, respectively, which 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 s incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (i) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (ii) 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. Other Property and Equipment — Other property and equipment consists of materials and supplies inventories, carried at weighted-average cost, and 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 business combinations. 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. 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. Debt Discounts and Premiums —Debt discounts and premiums related to the Company’s senior notes and convertible notes are included as a deduction from or addition to the carrying amount of the 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 notes. Derivative Instruments —The Company enters into derivative contracts, primarily costless collars and swaps, to manage its exposure to commodity price risk. Whiting follows FASB ASC Topic 815, Derivatives and Hedging , to account for its derivative financial instruments. 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. The Company does not currently apply hedge accounting to any of its outstanding derivative instruments, and as a result, all changes in derivative fair values are recognized currently in 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. Refer to the “Derivative Financial Instruments” footnote for further information. 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 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 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 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, and such revisions 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 18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the unit-of-production method. 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, 2017 and 2016 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. Stock-based Compensation Expense —The Company has share-based employee compensation plans that provide for the issuance of various types of stock-based awards, including shares of restricted stock , restricted stock units and stock option s, to employees and non-employee directors. The Company determines compensation expense for restricted stock awards and options granted under these plans based on the grant date fair value , and such expense is recognized on a straight-line basis over the requisite service period of the award. The Company determines compensation expense for cash-settled restricted stock units granted under these plans based on the fair value of such awards at the end of each reporting period, and such awards are recorded as a liability in the consolidated balance sheets . Gains and losses from changes in the fair value of restricted stock units are recognized immediately in earnings . The Company accounts for forfeitures of share-based awards as they occur. Refer to the “Stock-Based Compensation” footnote for further information. 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 2017, 2016 and 2015 were $8 million, $8 million and $12 million, respectively. Employees vest in employer contributions at 20% per year of completed service. 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 attributable 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 attributable 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 to be settled in cash, all using the treasury stock method. In addition, the diluted earnings per share calculation for the year ended December 31, 2016 considers the effect of convertible debt issued and converted during 2016, using the if-converted method for periods prior to their actual conversions. When a loss from continuing operations exists, all dilutive securities and 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. The following tables present 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, 201 7 and 201 6 . 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.  Year Ended December 31, 2017  Tesoro Crude Oil Co 18%    Year Ended December 31, 2016  Tesoro Crude Oil Co 15%  Jamex Marketing LLC 12%  Commodity derivative contracts held by the Company are with nine 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’s. As of December 31, 2017, outstanding derivative contracts with JP Morgan Chase Bank, N.A. , Wells Fargo Bank, N.A. , Capital One, N.A. and KeyBank, N.A. represented 24%, 17% , 14% and 10% , respectively, of total crude oil volumes hedged. 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. The FASB subsequently issued various ASUs which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments are 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 adopt ed these ASUs effective January 1, 2018 using the modified retrospective approach. The Company has completed the assessment of its contracts with customers and is in the process of implementing the changes to its financial statements, accounting policies and internal controls as a result of the adoption of these standards. The adoption is not expected to have a n impact on the Company’s net income or cash flows, however, it will result in changes to the classification of fees incurred under certain pipeline gathering and transportation agreements and gas processing agreements , as well as certain costs attributable to non-operated properties, which will result in an overall decrease in total revenues with a corresponding decrease in lease operating expenses under the new standards. In addition, the Company is continuing to assess the additional disclosures that will be required upon implementation of these ASUs. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”). The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be applied using a modified retrospective approach. Early adoption is permitted. Although the Company is still in the process of evaluating the effect of adopting ASU 2016 ‑02, the adoption is expected to result in (i) an increase in the assets and liabilities recorded on its consolidated balance sheet, (ii) an increase in depreciation, depletion and amortization expense and interest expense recorded on its consolidated statement of operations, and (iii) additional disclosures. As of December 31, 2017, the Company had approximately $ 73 million of contractual obligations related to its non-cancelable leases, drilling rig contracts and pipeline transportation agreements, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASU 2016-02. In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The objective of this ASU is to simplify several aspects of the accounting for employee share-based payment transactions, including income tax consequences, forfeitures, classification of awards as either equity or liabilities and classification in the statement of cash flows. Portions of this ASU must be applied prospectively while other portions may be applied either prospectively or retrospectively. ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, and the Company adopted this standard on January 1, 2017. Upon adoption of ASU 2016-09, the Company (i) recorded previously unrecognized excess tax benefits on a modified retrospective basis with a full valuation allowance, resulting in a net cumulative-effect adjustment to retained earnings of zero , (ii) prospectively removed excess tax benefits from its calculation of diluted shares, which had no impact on the Company’s diluted earnings per share for year ended December 31, 2017, and (iii) elected to account for forfeitures of share-based awards as they occur, rather than by applying an estimated forfeiture rate to determine compensation expense, the effect of which was recognized using a modified retrospective approach and resulted in an immaterial cumulative-effect adjustment to retained earnings and additional paid-in capital.

OIL AND GAS PROPERTIES

OIL AND GAS PROPERTIES	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 are as follows (in thousands):     December 31,  2017 2016  Proved leasehold costs $ 2,622,576 $ 3,330,928  Unproved leasehold costs 137,694 392,484  Costs of completed wells and facilities 8,288,591 9,016,472  Wells and facilities in progress 244,789 490,967  Total oil and gas properties, successful efforts method 11,293,650 13,230,851  Accumulated depletion (4,185,301) (4,170,237)  Oil and gas properties, net $ 7,108,349 $ 9,060,614 

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2017
ACQUISITIONS AND DIVESTITURES [Abstract]
ACQUISITIONS AND DIVESTITURES	3. ACQUISITIONS AND DIVESTITURES 2017 Acquisitions and Divestitures On September 1, 2017, the Company completed the sale of its interests in certain producing oil and gas properties located in the Fort Berthold Indian Reservation area in Dunn and McLean counties of North Dakota, as well as other related assets and liabilities, (the “FBIR Assets”) for aggregate sales proceeds of $500 million (before closing adjustments). The sale was effective September 1, 2017 and resulted in a pre-tax loss on sale of $402 million. The Company used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement. On January 1, 2017, the Company completed the sale of its 50% interest in the Robinson Lake gas processing plant located in Mountrail County, North Dakota and its 50% interest in the Belfield gas processing plant located in Stark County, North Dakota, as well as the associated natural gas, crude oil and water gathering systems, effective January 1, 2017, for aggregate sales proceeds of $375 million (before closing adjustments). The Company used the net proceeds from this transaction to repay a portion of the debt outstanding under its credit agreement. The following table shows the components of assets and liabilities classified as held for sale as of December 31, 2016 (in thousands):     Carrying Value as of  December 31, 2016  Assets  Oil and gas properties, net $ 347,817  Other property and equipment, net 475  Total property and equipment, net 348,292  Other long-term assets 854  Total assets held for sale $ 349,146   Liabilities  Asset retirement obligations $ 131  Other long-term liabilities 407  Total liabilities related to assets held for sale $ 538 There were no significant acquisitions during the year ended December 31, 2017. 2016 Acquisitions and Divestitures In July 2016, the Company completed the sale of its interest in its enhanced oil recovery project in the North Ward Estes field in Ward and Winkler counties of Texas, including Whiting’s interest in certain CO 2 properties in the McElmo Dome field in Colorado and certain other related assets and liabilities (the “North Ward Estes Properties”) for a cash purchase price of $300 million (before closing adjustments). The sale was effective July 1, 2016 and resulted in a pre-tax loss on sale of $187 million. The Company used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement. In addition to the cash purchase price, the buyer agreed to pay Whiting $100,000 for every $0.01 that, as of June 28, 2018, the average NYMEX crude oil futures contract price for each month from August 2018 through July 2021 is above $50.00/Bbl up to a maximum amount of $100 million (the “Contingent Payment”). The Company determined that this Contingent Payment was an embedded derivative and reflected it at fair value in the consolidated financial statements prior to settlement. On July 19, 2017, the buyer paid $35 million to Whiting to settle this Contingent Payment, resulting in a pre-tax gain of $3 million. Refer to the “Derivative Financial Instruments” and “Fair Value Measurements” footnotes for more information on this embedded derivative instrument. There were no significant acquisitions during the year ended December 31, 2016. 2015 Acquisitions and 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 aggregate sales proceeds 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 aggregate sales proceeds of $150 million (before closing adjustments) 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 aggregate sales proceeds of $108 million (before closing adjustments) resulting in a pre-tax gain on sale of $29 million. The properties were located in 187 fields across 14 states, and predominately consisted 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 aggregate sales proceeds of $176 million (before closing adjustments) resulting in a pre-tax gain on sale of $28 million. There were no significant acquisitions during the year ended December 31, 2015.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2017
LONG-TERM DEBT [Abstract]
LONG-TERM DEBT	4. LONG-TERM DEBT Long-term debt , including the current portion, consisted of the following at December 31, 201 7 and 201 6 (in thousands):     December 31,  2017 2016  Credit agreement $ - $ 550,000  6.5% Senior Subordinated Notes due 2018 - 275,121  5.0% Senior Notes due 2019 961,409 961,409  1.25% Convertible Senior Notes due 2020 562,075 562,075  5.75% Senior Notes due 2021 873,609 873,609  6.25% Senior Notes due 2023 408,296 408,296  6.625% Senior Notes due 2026 1,000,000 -  Total principal 3,805,389 3,630,510  Unamortized debt discounts and premiums (50,945) (71,340)  Unamortized debt issuance costs on notes (31,015) (23,867)  Total debt 3,723,429 3,535,303  Less current portion of long-term debt (958,713) -  Total long-term debt $ 2,764,716 $ 3,535,303 The following table shows five succeeding fiscal years of anticipated maturities for the Company’s long-term debt as of December 31, 201 7 (in thousands):    2018 2019 2020 2021 2022  Long-term debt $ 961,409 $ - $ 562,075 $ 873,609 $ - 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, 201 7 had a borrowing base and aggregate commitments of $2.3 billion. As of December 31, 201 7 , the Company had $2.3 billion of available borrowing capacity, which was net of $2 million in letters of credit outstanding , with no borrowings outstanding . 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. In October 2017, the borrowing base and aggregate commitments under the facility were reduced from $2.5 billion to $2.3 billion in connection with the November 1, 2017 regular borrowing base redetermination, and was primarily a result of the sale of the Company’s FBIR Assets on September 1, 2017. A portion of the revolving credit facility in an aggregate amount not to exceed $50 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, 201 7 , $48 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 interes t expense. At December 31, 2016 , the weighted average interest rate on the outstanding principal balance under the credit agreement was 4.0% .     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 1.00% 2.00% 0.50%  Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 1.25% 2.25% 0.50%  Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 1.50% 2.50% 0.50%  Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 1.75% 2.75% 0.50%  Greater than or equal to 0.90 to 1.0 2.00% 3.00% 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. However, the credit agreement permits the Company and certain of its subsidiaries to issue second lien indebtedness of up to $1.0 billion subject to certain conditions and limitations. 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, 201 7 , there were no retained earnings free from restrictions. The 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 3.0 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 cash interest charges of not less than 2.25 to 1.0 during the Interim Covenant Period. Under the credit agreement, the “Interim Covenant Period” is defined as the period from June 30, 2015 until the earlier of ( i ) April 1, 2018 or ( ii ) the commencement of an investment-grade debt rating period ( as defined in the credit agreement) . The Company was in compliance with its covenants under the credit agreement as of December 31, 201 7 . The obligations of Whiting Oil and Gas under the credit agreement are collateralized by a first lien on substantially all of Whiting Oil and Gas’ and Whiting Resource Corporation’s properties. 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, Convertible Senior Notes and Senior Subordinated Notes The following table summarizes the material terms of the Company’s senior notes and convertible senior notes outstanding at December 31, 2017:     2020  2019 Convertible 2021 2023 2026  Senior Notes (1) Senior Notes Senior Notes Senior Notes Senior Notes  Outstanding principal (in thousands) $ 961,409 $ 562,075 $ 873,609 $ 408,296 $ 1,000,000  Interest rate 5.0% 1.25% 5.75% 6.25% 6.625%  Maturity date Mar 15, 2019 Apr 1, 2020 Mar 15, 2021 Apr 1, 2023 Jan 15, 2026  Interest payment dates Mar 15, Sep 15 Apr 1, Oct 1 Mar 15, Sep 15 Apr 1, Oct 1 Jan 15, Jul 15  Make-whole redemption date (2) Dec 15, 2018 N/A (3) Dec 15, 2020 Jan 1, 2023 Oct 15, 2025 _____________________ (1) On January 26, 2018, the Company used the proceeds from the December 2017 issuance of its 6.625% Senior Notes due January 2026 as well as borrowings under its credit agreement to redeem all of the outstanding 5.0% Senior Notes due March 2019. (2) On or after these dates, the Company may redeem the applicable series of notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. At any time prior to these dates, the Company may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes. (3) The indenture governing the 1.25% Convertible Senior Notes due 2020 does not allow for optional redemption by the Company prior to the maturity date. 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”). In September 2013, the Company issued at par $1.1 billion of 5.0% 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 debt premium recorded in connection with the issuance of the 2021 Senior Notes is being 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. In March 2015, the Company issued at par $750 million of 6.25% Senior Notes due April 2023 (the “2023 Senior Notes” ). Issuance of Senior Notes. In December 2017, the Company issued at par $1.0 billion of 6.625% Senior Notes due January 2026 (the “2026 Senior Notes” and together with the 2019 Senior Notes , the 2021 Senior Notes and the 2023 Senior Notes , the “Senior Notes” ). The Company used the net proceeds from this offering to redeem on January 26, 2018 all of the outstanding 2019 Senior Notes at a 102.976% redemption price plus all accrued and unpaid interest on the notes. Refer to the “Subsequent Events” footnote for more information on the redemption of the 2019 Senior Notes. Exchange of Senior Notes and Senior Subordinated Notes for Convertible Notes . On March 23, 2016, the Company completed the exchange of $477 million aggregate principal amount of Senior Notes and 2018 Senior Subordinated Notes, consisting of (i) $49 million aggregate principal amount of its 2018 Senior Subordinated Notes, (ii) $97 million aggregate principal amount of its 2019 Senior Notes, (iii) $152 million aggregate principal amount of its 2021 Senior Notes, and (iv) $179 million aggregate principal amount of its 2023 Senior Notes, for $477 million aggregate principal amount of convertible senior notes and convertible senior subordinated notes (the “New Convertible Notes”). This exchange transaction was accounted for as an extinguishment of debt for each portion of the Senior Notes and 2018 Senior Subordinated Notes that was exchanged. As a result, Whiting recognized a $91 million gain on extinguishment of debt, which was net of a $4 million non-cash charge for the acceleration of unamortized debt issuance costs and debt premium on the original notes. Each series of New Convertible Notes was recorded at fair value upon issuance, with the difference between the principal amount of the notes and their fair values, totaling $95 million, recorded as a debt discount. The aggregate debt discount of $185 million recorded upon issuance of the New Convertible Notes also included $90 million related to the fair value of the holders’ conversion options, which were embedded derivatives that met the criteria to be bifurcated from their host contracts and accounted for separately. Refer to the “Derivative Financial Instruments” and “Fair Value Measurements” footnotes for more information on these embedded derivatives. During the second quarter of 2016, holders of the New Convertible Notes voluntarily converted all $477 million aggregate principal amount of the New Convertible Notes for approximately 10.5 million shares of the Company’s common stock. Upon conversion, the Company paid $46 million in cash consisting of early conversion payments to the holders of the notes, as well as all accrued and unpaid interest on such notes. As a result of the conversions, Whiting recognized a $188 million loss on extinguishment of debt, which consisted of a non-cash charge for the acceleration of unamortized debt issuance costs and debt discount on the notes. As of June 30, 2016, no New Convertible Notes remained outstanding. Exchange of Senior Notes and Senior Subordinated Notes for Mandatory Convertible Notes. On July 1, 2016, the Company completed the exchange of $405 million aggregate principal amount of Senior Notes and 2018 Senior Subordinated Notes for the same aggregate principal amount of new mandatory convertible senior notes and mandatory convertible senior subordinated notes. Refer to “Mandatory Convertible Notes” below for more information on these exchange transactions. Kodiak Senior Notes. In conjunction with the acquisition of Kodiak in December 2014 , 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”). I n January 2015, Whiting offered to repurchase at 101% of par all $1,550 million principal amount of Kodiak Notes then outstanding. I n March 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 u npaid interest on such notes. I n May 2015, Whiting paid an additional $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. I n December 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. As a result of the repurchases, Whiting recognized an $18 million loss on 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. As of December 31, 2015, no Kodiak Notes remained outstanding. Redemption of 2018 Senior Subordinated Notes. On February 2, 2017, the Company paid $281 million to redeem all of the then outstanding $275 million aggregate principal amount of 2018 Senior Subordinated Notes, which payment consisted of the 100% redemption price plus all accrued and unpaid interest on the notes . The Company financed the redemption with borrowings under its credit agreement. As a result of the redemption, Whiting recognized a $2 million loss on extinguishment of debt, which consisted of a non-cash charge for the acceleration of unamortized debt issuance costs on the notes. As of March 31, 2017, no 2018 Senior Subordinated Notes remained outstanding. 2020 Convertible Senior Notes —In March 2015, the Company issued at par $1,250 million of 1.25% Convertible Senior Notes due April 2020 (the “ 2020 Convertible Senior Notes”) for net proceeds of $1.2 billion, net of initial purchasers’ fees of $25 million. On June 29, 2016, the Company exchanged $129 million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes, and on July 1, 2016, the Company exchanged $559 million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes. Refer to “Mandatory Convertible Notes” below for more information on these exchange transactions. For the remaining $562 million aggregate principal amount of 2020 Convertible Senior Notes outstanding as of December 31, 2017, t he 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 2020 Convertible Senior Notes in cash upon conversion. Prior to January 1, 2020, the 2020 Convertible Senior Notes will be convertible at the holder’s option 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 2020 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 2020 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 a current conversion rate of 6.4102 shares of Whiting’s common stock per $1,000 principal amount of the notes, which is equivalent to a current conversion price of approximately $156.00 . 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 2020 Convertible Senior Notes in connection with such corporate event. As of December 31, 201 7 , none of the contingent conditions allowing holders of the 2020 Convertible Senior Notes to convert these notes had been met. Upon issuance, the Company separately accounted for the liability and equity components of the 2020 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 2020 Convertible Senior Notes and the estimated fair value of the liability component was recorded as a debt discount and is being 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 liability component of the 2020 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 2020 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 2020 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 interest 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 2020 Convertible Senior Notes consist ed of the following at December 31, 201 7 and 2016 (in thousands):     December 31,  2017 2016  Liability component  Principal $ 562,075 $ 562,075  Less: unamortized note discount (51,666) (72,622)  Less: unamortized debt issuance costs (4,178) (5,988)  Net carrying value $ 506,231 $ 483,465  Equity component (1) $ 136,522 $ 136,522 (1) Recorded in additional paid-in capital, net of $5 million of issuance costs and $50 million of deferred taxes as of December 31, 2017 and 2016. Interest expense recognized on the 2020 Convertible Senior Notes related to the stated interest rate and amortization of the debt discount totaled $28 million, $43 million and $44 million for the year s ended December 31, 201 7, 2016 and 2015, respectively.   Mandatory Convertible Notes — On June 29, 2016, the Company completed the exchange of $129 million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible notes, and on July 1, 2016, the Company completed the exchange of $964 million aggregate principal amount of Senior Notes, 2020 Convertible Senior Notes and 2018 Senior Subordinated Notes, consisting of (i) $26 million aggregate principal amount of 2018 Senior Subordinated Notes, (ii) $42 million aggregate principal amount of 2019 Senior Notes, (iii) $559 million aggregate principal amount of 2020 Convertible Senior Notes, (iv) $174 million aggregate principal amount of 2021 Senior Notes, and (v) $163 million aggregate principal amount of 2023 Senior Notes, for the same aggregate principal amount of new mandatory convertible notes (together the “Mandatory Convertible Notes”). These transactions were accounted for as extinguishments of debt for the portions of Senior Notes, 2020 Convertible Senior Notes and 2018 Senior Subordinated Notes that were exchanged. As a result, Whiting recognized a $57 million gain on extinguishment of debt, which was net of a $113 million charge for the non-cash write-off of unamortized debt issuance costs, debt discounts and debt premium on the original notes. In addition, Whiting recorded a $63 million reduction to the equity component of the 2020 Convertible Senior Notes, which was net of deferred taxes. The Mandatory Convertible Notes were recorded at fair value upon issuance with the difference between the principal amount of the notes and their fair values, totaling $69 million, recorded as a debt discount. The Mandatory Convertible Notes contained contingent beneficial conversion features, the intrinsic value of which was recognized in additional paid-in capital at the time the contingency was resolved, resulting in an additional debt discount of $233 million. The aggregate debt discount of $302 million was being amortized to interest expense over the term of the notes using the effective interest method. The July 1, 2016 note exchange transactions triggered an ownership shift as defined under Section 382 of the Internal Revenue Code due to the “deemed share issuance” that resulted from the note exchanges. This triggering event will limit the Company’s usage of certain of its net operating losses and tax credits in the future. Refer to the “Income Taxes” footnote for more information. During the second half of 2016, the entire $1,093 million aggregate principal amount of the Mandatory Convertible Notes were converted into approximately 28.9 million shares of the Company’s common stock pursuant to the terms of the notes. As a result of these conversions, Whiting recognized (i) a $259 million non-cash charge for the acceleration of unamortized debt discounts on the notes, which is included in interest expense in the consolidated statements of operations, and (ii) a $1 million net loss on extinguishment of debt. As of December 31, 2016, no Mandatory Convertible Notes remained outstanding. Security and Guarantees The Senior Notes and the 2020 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 Company’s obligations under the Senior Notes and the 2020 Convertible Senior Notes are guaranteed by the Company’s 100% ‑ 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, 2017
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 current portions at December 31, 201 7 and 201 6 were $5 million and $8 million, respectively, and have been included in accrued liabilities and other in the consolidated balance sheets . The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 201 7 and 201 6 (in thousands):     2017 2016  Asset retirement obligation at January 1 $ 177,004 $ 161,908  Additional liability incurred 7,727 3,238  Revisions to estimated cash flows (1) (2) (52,947) 11,620  Accretion expense 13,809 13,800  Obligations on sold properties (6,988) (4,771)  Liabilities settled (4,368) (8,791)  Asset retirement obligation at December 31 $ 134,237 $ 177,004 (1) Revisions to estimated cash flows during the year ended December 31, 2017 are primarily attributable to the deferral of the estimated timing of abandonment of a large number of Whiting’s producing properties resulting from in creases in commodity prices used in the calculation of the Company’s reserves as of December 31, 2017 , which lengthened the economic lives of these properties. In addition, during 2017 there were decreases in the estimates of future costs required to plug and abandon wells in certain fields in the Northern Rocky Mountains. (2) R evisions to estimated cash flows during the year ended December 31, 2016 are primarily attributable to the a cceleration in the estimated timing of abandonment of a large number of Whiting’s producing properties resulting from de creases in commodity prices used in the calculation of the Company’s reserves as of December 31, 201 6, which shortened the economic lives of these properties . For the year ended December 31, 2016, the increase was partially offset by decreases in the estimates of future costs required to plug and abandon wells in certain fields in the Central and Northern Rocky Mountains.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2017
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 it uses derivative instruments to manage its commodity price risk. In addition, the Company periodically enters into contracts that contain embedded features which are required to be bifurcated and accounted for separately as derivatives. 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 primarily enters into derivative contracts such as crude oil costless collars and swaps , as well as sales and delivery contracts , to achieve a more predictable cash flow by reducing its exposure to commodity price volatility , thereby ensur ing adequate fund ing for the Company’s capital programs and facilitating the management of 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 December 31 , 201 7 .       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 2018 17,400,000 $37.07 - $47.07 - $57.30  Total 17,400,000 _____________________ (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. (2) Subsequent to December 31, 2017 , the Company entered into additional swap contracts for 4,400,000 Bbl of crude oil volumes for the year ended December 31, 2018 , as well as costless collars for 900,000 Bbl of crude oil volumes for the six months ended June 30, 2019 . Crude Oil Sales and Delivery Contract. As of December 31, 2017, the Company ha d 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 ha d committed to deliver certain fixed volumes of crude oil through April 2020. The Company determined it was not probable that future oil production from its Redtail field would be sufficient to meet the minimum volume requirement s specified in this contract ; accordingly, 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, 201 7 and 2016 , the estimated fair value of this derivative contract was a liability of $ 63 million and $9 million, respectively . On February 1, 2018, Whiting paid $61 million to the counterparty to settle all future minimum volume commitments under this agreement. Accordingly, this crude oil sales and delivery contract was fully terminated and the fair value of this corresponding derivative was therefore zero as of that date. Embedded Derivatives — I n March 2016, the Company issued convertible notes that contained debtholder conversion options which the Company determined were not clearly and closely related to the debt host contracts, and the Company therefore bifurcated these embedded features and reflected them at fair value in the consolidated financial statements. During the second quarter of 2016, the entire aggregate principal amount of these notes was converted into shares of the Company’s common stock, and the fair value of these embedded derivatives as of December 31, 2017 and 2016 was therefore zero . In July 2016, the Company entered into a purchase and sale agreement with the buyer of its North Ward Estes Properties, whereby the buyer agreed to pay Whiting additional proceeds of $100,000 for every $0.01 that, as of June 28, 2018, the average NYMEX crude oil futures contract price for each month from August 2018 through July 2021 is above $50.00/Bbl up to a maximum amount of $100 million. The Company determined that this NYMEX-linked contingent payment was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded feature and reflected it at its estimated fair value of $51 million in the consolidated financial statements as of December 31, 2016. On July 19, 2017, the buyer paid $35 million to Whiting to settle this NYMEX-linked contingent payment, and accordingly, the embedded derivative’s fair value was zero as of December 31, 2017. 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 or other derivative scope exceptions . The following table summarize s the effects of derivative instruments on the consolidated statements of operations for the years ended December 31, 201 7 , 201 6 and 201 5 (in thousands):      (Gain) Loss Recognized in Income  Not Designated as Statement of Operations Year Ended December 31,  ASC 815 Hedges Classification 2017 2016 2015  Commodity contracts Derivative (gain) loss, net $ 104,138 $ 58,771 $ (217,972)  Embedded derivatives Derivative (gain) loss, net 18,709 (59,358) -  Total $ 122,847 $ (587) $ (217,972)  Offsetting of Derivative Assets and Liabilities. 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 the Company’s 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, 2017 (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 Prepaid expenses and other $ 9,829 $ (9,829) $ -  Total derivative assets $ 9,829 $ (9,829) $ -  Derivative liabilities  Commodity contracts - current Derivative liabilities $ 142,354 $ (9,829) $ 132,525  Total derivative liabilities $ 142,354 $ (9,829) $ 132,525      December 31, 2016 (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 Prepaid expenses and other $ 21,405 $ (21,405) $ -  Commodity contracts - non-current Other long-term assets 9,495 (9,495) -  Embedded derivatives - non-current Other long-term assets 50,632 - 50,632  Total derivative assets $ 81,532 $ (30,900) $ 50,632  Derivative liabilities  Commodity contracts - current Derivative liabilities $ 39,033 $ (21,405) $ 17,628  Commodity contracts - non-current Other long-term liabilities 19,724 (9,495) 10,229  Total derivative liabilities $ 58,757 $ (30,900) $ 27,857 _____________________ (1) Because counterparties to the Company’s financial derivative contracts subject to master netting arrangements 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 these tables. 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, 2017
FAIR VALUE MEASUREMENTS [Abstract]
FAIR VALUE MEASUREMENTS	7. FAIR VALUE MEASUREMENTS 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. Cash , cash equivalents , restricted cash , 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 and the applicable margins represent market rates. The Company’s senior notes and senior subordinated notes are recorded at cost, and the Company’s convertible senior notes are recorded at fair value at the date of issuance. The following table summarizes the fair values and carrying values of these instruments as of December 31, 2017 and 2016 (in thousands):     December 31, 2017 December 31, 2016  Fair Carrying Fair Carrying  Value (1) Value (2) Value (1) Value (2)  6.5% Senior Subordinated Notes due 2018 $ - $ - $ 275,121 $ 273,506  5.0% Senior Notes due 2019 985,444 958,713 961,409 956,607  1.25% Convertible Senior Notes due 2020 517,109 506,231 503,057 483,465  5.75% Senior Notes due 2021 897,633 869,284 868,149 868,460  6.25% Senior Notes due 2023 418,503 403,940 408,296 403,265  6.625% Senior Notes due 2026 1,025,000 985,261 - -  Total $ 3,843,689 $ 3,723,429 $ 3,016,032 $ 2,985,303 (1) 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. (2) Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums. The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance ri sk or that of its counterparty , as appropriate. 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, 201 7 and 201 6 , 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, 2017  Financial Liabilities  Commodity derivatives – current $ - $ 69,247 $ 63,278 $ 132,525  Total financial liabilities $ - $ 69,247 $ 63,278 $ 132,525      Total Fair Value  Level 1 Level 2 Level 3 December 31, 2016  Financial Assets  Embedded derivatives – non-current $ - $ 50,632 $ - $ 50,632  Total financial assets $ - $ 50,632 $ - $ 50,632  Financial Liabilities  Commodity derivatives – current $ - $ 14,664 $ 2,964 $ 17,628  Commodity derivatives – non-current - 3,979 6,250 10,229  Total financial liabilities $ - $ 18,643 $ 9,214 $ 27,857 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 for crude oil. The Company’s costless collars are valued based on an income approach. T he option model consider s 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 ha d a long-term crude oil sales and delivery contract, whereby it had committed to deliver certain fixed volumes of crude oil through April 2020. Whiting 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 a probability-weighted income approach which considers various assumptions, including quoted spot 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. On February 1, 2018, Whiting paid $61 million to the counterparty to settle all future minimum volume commitments under this agreement. Accordingly, this derivative was settled in its entirety as of that date. Embedded Derivatives . The Company had embedded derivatives related to its convertible notes that were issued in March 2016. The notes contained debtholder conversion options which the Company determined were not clearly and closely related to the debt host contracts and the Company therefore bifurcated these embedded features and reflected them at fair value in the consolidated financial statements . Prior to their settlements, the fair values of these embedded derivatives were determined using a binomial lattice model which considered various inputs including (i) Whiting’s common stock price, (ii) risk-free rates based on U.S. Treasury rates, (iii) recovery rates in the event of default, (iv) default intensity, and (v) volatility of Whiting’s common stock. The expected volatility and default intensity used in the valuation were unobservable in the marketplace and significant to the valuation methodology, and the embedded derivatives’ fair value was therefore designated as Level 3 in the valuation hierarchy. During the second quarter of 2016, the entire aggregate principal amount of these convertible notes was converted into shares of the Company’s common stock. Accordingly, the embedded derivatives were settled in their entirety as of June 30, 2016. The Company had an embedded derivative related to its purchase and sale agreement with the buyer of the North Ward Estes Properties. The agreement included a Contingent Payment linked to NYMEX crude oil prices which the Company determined was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded feature and reflected it at fair value in the consolidated financial statements prior to settlement. The fair value of this embedded derivative was determined using a modified Black-Scholes swaption pricing model which considers various assumptions, including quoted forward prices for commodities, time value and volatility factors. These assumptions were observable in the marketplace throughout the full term of the financial instrument , could be derived from observable data or were supported by observable levels at which transactions are executed in the marketplace, and were therefore designated as Level 2 within the valuation hierarchy. The discount rate used in the fair value of this instrument included a measure of the counterparty’s nonperformance risk. On July 19, 2017, the buyer paid $35 million to Whiting in satisfaction of this Contingent Payment. Accordingly, the embedded derivative was settled in its entirety as of that date. Level 3 Fair Value Measurements — A third-party valuation specialist is utilized in determin ing the fair value of the Company’s derivative instruments designated as Level 3. The Co mpany reviews these valuations, including the relat ed 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, 201 7 and 201 6 (in thousands):     Year Ended December 31,  2017 2016  Fair value liability, beginning of period $ (9,214) $ (4,027)  Recognition of embedded derivatives associated with convertible note issuances - (89,884)  Unrealized gains on embedded derivatives included in earnings (1) - 47,965  Settlement of embedded derivatives upon conversion of convertible notes - 41,919  Unrealized losses on commodity derivative contracts included in earnings (1) (54,064) (5,187)  Transfers into (out of) Level 3 - -  Fair value liability, end of period $ (63,278) $ (9,214) _____________________ (1) Included in derivative ( gain ) loss , net in the consolidated statements of operations. Quantitative Information a bout Level 3 Fair Value Measurements. The significant unobservable inputs used in the fair value measurement of the Company’s commodity derivative instrument designated as Level 3 are as follows:     Derivative Instrument Valuation Technique Unobservable Input Amount  Commodity derivative contract Probability-weighted i ncome approach Market differential for crude oil $4.08 - $4.92 per Bbl Sensitivity to Changes i n 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 lower or higher , 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. 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 Company did not recognize any impairment write-downs with respect to its proved property during the year ended December 31, 2016. The following table presents information about the Company’s non-financial assets measured at fair value on a non-recurring basis for the year ended December 31, 2017, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands):   Loss (Before  Net Carrying Tax) Year  Value as of Ended  December 31, Fair Value Measurements Using December 31,  2017 Level 1 Level 2 Level 3 2017  Proved property (1) $ 389,390 $ - $ - $ 389,390 $ 834,950 _____________________ (1) During the fourth quarter of 2017, proved oil and gas properties at the Redtail field in the Denver Julesburg Basin (the “ DJ Basin ”) in Weld County, Colorado, with a previous carrying amount of $1.2 billion were written down to their fair value as of December 31, 2017 of $ 389 million, resulting in a non-cash impairment charge of $ 835 m illion which was 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 table 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. Based on recent well performance results in the DJ Basin, the Company reduced its reserves at its Redtail field during the fourth quarter of 2017, and performed a proved property impairment test as of December 31, 2017. The fair value was ascribed using income approach analyses based on the net discounted future cash flows from the producing property and related assets. The discounted cash flows were based on management’s expectations for the future. Unobservable inputs included 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 were designated as Level 3 inputs within the fair value hierarchy). The impairment test 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 December 31, 2017.

SHAREHOLDERS_ EQUITY AND NONCON

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST	12 Months Ended
	Dec. 31, 2017
SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST [Abstract]
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST	8 . SHAREHOLDERS ’ EQUITY AND NONCONTROLLING INTEREST Common Stock Reverse Stock Split. On November 8, 2017 and following approval by the Company’s stockholders of an amendment to its certificate of incorporation to effect a reverse stock split, the Company’s Board of Directors approved a reverse stock split of Whiting’s common stock at a ratio of one -for-four and a reduction in the number of authorized shares of the Company’s common stock from 600,000,000 shares to 225,000,000 . Whiting’s common stock began trading on a split-adjusted basis on November 9, 2017 upon opening of the markets. All share and per share amounts in these consolidated financial statements and related notes for periods prior to November 2017 have been retroactively adjusted to reflect the reverse stock split. Common Stock Offering. In March 2015, the Company completed a public offering of its common stock, selling 8,750,000 shares of common stock at a price of $120.00 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 1,312,500 shares of common stock. On April 1, 2015, the underwriter exercised its right to purchase an additional 500,000 shares of common stock, providing additional net proceeds of $61 million. Noncontrolling Interest —The Company’s noncontrolling interest represent ed an unrelated third party’s 25% ownership interest in Sustainable Water Resources, LLC (“SWR”) . During the third quarter of 2017, the third party’s ownership interest in SWR was assigned back to SWR. The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):    Year Ended December 31,  2017 2016  Balance at beginning of period $ 7,962 $ 7,984  Net loss (14) (22)  Conveyance of ownership interest (7,948) -  Balance at end of period $ - $ 7,962 

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2017
STOCK-BASED COMPENSATION [Abstract]
STOCK-BASED COMPENSATION	9. STOCK-BASED COMPENSATION Equity Incentive Plan — T he Company maintains the Whiting Petroleum Corporation 2013 Equity Incentive Plan , as amended and restated (the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and include s the authority to issue 1,375,000 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 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 225,000 shares of common stock, stock appreciation rights relating to more than 225,000 shares of common stock, more than 150,000 shares of restricted stock, more than 150,000 restricted stock units, more than 150,000 performance shares, or more than 150,000 performance units during any calendar year. In addition, no non-employee director participant may be granted options for more than 25,000 shares of common stock, stock appreciation rights relating to more than 25,000 shares of common stock, more than 25,000 shares of restricted stock, or more than 25,000 restricted stock units during any calendar year. As of December 31, 2017, 1,137,723 shares of common stock remained available for grant under the 2013 Equity Plan. Restricted Stock, Restricted Stock Units and Performance Shares —The Company grants service-based restricted stock awards and restricted stock units to executive officers and employees, which generally vest ratably over a three - year service period . The Company also grants service-based restricted stock awards to directors, which generally vest over a one -year service period. In addition, the Company grants performance share awards to executive officers that are subject to market-based vesting criteria as well as a three -year service period. Upon adoption of ASU 2016-09 on January 1, 2017, the Company elected to account for forfeitures of awards granted under these plans as they occur in determining compensation expense. The Company recognizes compensation expense for all awards subject to market -based vesting 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. During 2017, 2016 and 2015, 538,194 , 737,912 and 205,971 shares, respectively, of service-based restricted stock awards were granted to employees, executive officers and directors under the 2013 Equity Plan. The grant date fair value of restricted stock awards is determined based on the closing bid price of the Company’s common stock on the grant date. The weighted average grant date fair value of restricted stock awards was $40.66 per share, $27.82 per share and $123.72 per share for the years ended December 31, 2017, 2016, and 2015, respectively. During 2017, 201 6 and 2015, 168,466 , 268,278 and 97,937 performance shares , respectively, 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 is 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. For awards subject to market conditions, the grant date fair value is 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 i s 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 se market-based awards were as follows:    2017 2016 2015  Number of simulations 2,500,000 2,500,000 2,500,000  Expected volatility 82.44% 60.8% 40.3%  Risk-free interest rate 1.52% 1.13% 0.99%  Dividend yield - - -  The weighted average grant date fair value of the market-based awards as determined by the Monte Carlo valuation model was $63.04 per share, $25.56 per share and $133.00 per share in 201 7 , 201 6 and 201 5 , respectively. The following table shows a summary of the Company’s restricted stock award (“RSA”), restricted stock unit (“RSU”) and performance share activity for the year ended December 31, 201 7 :    Number of Awards Weighted Average  Service-Based Service-Based Market-Based Grant Date  RSAs RSUs Performance Awards Fair Value  Nonvested awards, January 1 766,818 - 523,172 $ 54.19  Granted 538,194 39,619 168,466 44.89  Vested (339,199) - - 51.23  Forfeited (67,392) - (194,111) 81.97  Nonvested awards, December 31 898,421 39,619 497,527 $ 44.99 As of December 31, 201 7 , there was $18 million of total unrecognized compensation cost related to unvested awards granted under the stock incentive plans. That cost is expected to be recognized over a weighted average period of 2.0 years. For the years ended December 31, 201 7 , 201 6 and 201 5 , the total fair value of restricted stock vested was $15 million, $5 million and $4 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 the 2013 Equity Plan during 201 7 , 201 6 or 201 5 . 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, 201 7 as w ell as activity during the year 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 1 128,524 $ 158.17  Granted - -  Exercised - - $ -  Forfeited or expired (6,490) 207.86  Options outstanding at December 31 122,034 $ 154.32 $ 28 2.4  Options vested at December 31 122,034 $ 154.32 $ 28 2.4  Options exercisable at December 31 122,034 $ 154.32 $ 28 2.4 There was no unrecognized compensation cost related to unvested stock option awards as of December 31, 201 7 . There were no stock options exercised during the years ended December 31, 2017 or 2016. For the year ended December 31, 201 5 , the aggregate intrinsic value of stock options exercised was $ 2 million. For the years ended December 31, 201 7 , 201 6 and 201 5 , total stock compensation expense recognized for restricted share awards and stock options was $22 million, $26 million and $28 million, respectively.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2017
INCOME TAXES [Abstract]
INCOME TAXES	10. INCOME TAXES Income tax benefit consists of the following (in thousands):     Year Ended December 31,  2017 2016 2015  Current income tax expense (benefit)  Federal $ (7,305) $ (7,340) $ -  State 14 150 (357)  Total current income tax benefit (7,291) (7,190) (357)  Deferred income tax benefit  Federal (398,686) (65,130) (736,520)  State (77,002) (15,326) (37,350)  Total deferred income tax benefit (475,688) (80,456) (773,870)  Total $ (482,979) $ (87,646) $ (774,227)  Income tax 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,  2017 2016 2015  U.S. statutory income tax benefit $ (602,219) $ (499,370) $ (1,047,723)  State income taxes, net of federal benefit (39,557) (33,050) (44,654)  Valuation allowance 120,880 - -  Federal tax reform (42,033) - -  Impairment charge after enactment of federal tax reform 114,293 - -  IRC Section 382 limitation (45,899) 259,494 -  Non-deductible convertible debt expenses - 174,071 -  Goodwill impairment - - 305,820  Market-based equity awards 7,003 8,352 2,690  Enacted changes in state tax laws - 5,020 7,350  Other 4,553 (2,163) 2,290  Total $ (482,979) $ (87,646) $ (774,227)  The principal components of the Company’s deferred income tax assets and liabilities at December 31, 201 7 and 201 6 were as follows (in thousands):      Year Ended December 31,  2017 2016  Deferred income tax assets  Net operating loss carryforward $ 828,617 $ 1,248,034  Derivative instruments 31,567 6,145  Asset retirement obligations 16,138 21,398  Restricted stock compensation 9,704 12,171  EOR credit carryforwards 7,946 7,946  Alternative minimum tax credit carryforwards - 7,847  Other 11,549 19,356  Total deferred income tax assets 905,521 1,322,897  Less valuation allowance (271,300) (264,461)  Net deferred income tax assets 634,221 1,058,436  Deferred income tax liabilities  Oil and gas properties 566,747 1,412,781  Trust distributions 54,980 94,120  Discount on convertible senior notes 12,494 27,224  Total deferred income tax liabilities 634,221 1,534,125  Total net deferred income tax liabilities $ - $ 475,689  The Company’s July 1, 2016 note exchange transactions triggered an ownership shift within the meaning of Section 382 of the Internal Revenue Code (“IRC”) due to the “deemed share issuance” that resulted from the note exchanges. The ownership shift will limit Whiting’s usage of certain of its net operating losses and tax credits in the future. Accordingly, the Company recognized valuation allowances on its deferred tax assets totaling $259 million. In the third quarter of 2017 there was a partial release of this valuation allowance in the amount of $41 million associated with built-on gains on the sale of the FBIR Assets. As of December 31, 201 7 , the Company had federal net operating loss (“NOL”) carryforwards of $2.9 billion , which was net of the IRC Section 382 limitation . 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 203 7 , and the state NOLs will expire between 201 8 and 203 7 . 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, 201 7 , the Company had recognized aggregate EOR credits of $8 million. As a result of the IRC Section 382 limitation in July 2016, the Company recorded a full valuation allowance on these credits . The Company was subject to the alternative minimum tax (“AMT”) principally due to its significant intangible drilling cost deductions. For 2017, the Company expects to forego bonus depreciation and claim a refund under the Protecting Americans from Tax Hikes Act for its AMT credits and has recognized a $7 million current benefit. As of December 31, 201 7 , the Company had no remaining AMT credits available to offset future regular federal income taxes. On December 22, 2017, Congress passed the Tax Cuts and Jobs Act (the “TCJA”). The new legislation significantly changes the U.S. corporate tax law by, among other things, lowering the U.S. corporate income tax rate from 35% to 21% beginning in January 2018, implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. FASB ASC Topic 740, Income Taxes , requires companies to recognize the impact of the changes in tax law in the period of enactment. The SEC issued Staff Accounting Bulletin No. 118 (“SAB 118”), which allows registrants to record provisional amounts during a one year “measurement period” similar to that used to account for business combinations, however, the measurement period is deemed to have ended earlier when the registrant has obtained, prepared and analyzed the information necessary to finalize its accounting. During the measurement period, impacts of the law are expected to be recorded at the time a reasonable estimate for all or a portion of the effects can be made, and provisional amounts can be recognized and adjusted as information becomes available, prepared or analyzed. SAB 118 outlines a three-step process to be applied at each reporting period to account for and qualitatively disclose (i) the effects of the change in tax law for which accounting is complete, (ii) provisional amounts (or adjustments to provisional amounts) for the effects of the change in tax law where accounting is not complete, but where a reasonable estimate has been made, and (iii) areas affected by the change in tax law where a reasonable estimate cannot yet be made and therefore taxes are reflected in accordance with law prior to the enactment of the TCJA. Amounts recorded during the year ended December 31, 2017 related to the TCJA principally relate to the reduction in the U.S. corporate income tax rate to 21%, which resulted in (i) income tax expense of $5 1 million from the revaluation of the Company’s deferred tax assets and liabilities as of the date of enactment and (ii) an income tax benefit totaling $93 million related to a reduction in the Company’s existing valuation allowances. Reasonable estimates were made based on the Company’s analysis of the remeasurement of its deferred tax assets and liabilities and valuation allowances under tax reform. These provisional amounts may be adjusted in future periods if additional information is obtained or further clarification and guidance is issued by regulatory authorities regarding the application of the law. Other provisions of the TCJA that do not impact 2017, but may impact income taxes in future years include (i) a limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income, (ii) a limitation on the usage of NOLs generated after 2017 to 80% of taxable income, (iii) additional limitations on certain meals and entertainment expenses, (iv) the inclusion of performance based compensation in determining the excessive compensation limitation, and (v) the unlimited carryforward of NOLs. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion, or all, of the Company’s deferred tax assets will not be realized. In making such determination, the Company considers all available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and projected future taxable income and results of operations. If the Company concludes that it is more likely than not that some portion, or all, of its deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. At December 31, 2017, after considering the impact of the federal tax rate reduction resulting from the enactment of the TCJA , the Company had a valuation allowance totaling $ 271 million, comprised of $138 million of NOL carryforward limitations under Section 382 of the IRC, $8 million of EOR credits, which will expire between 2023 and 2025, $5 million of Canadian NOL carryforwards, which will expire between 2034 and 2035, and $1 million of short-term capital loss carryforwards that are not expected to be realized . In addition, the Company has determined that it does not expect the carrying value of its deferred tax assets to be realized, and accordingly, has recorded a full valuation allowance totaling $11 9 million on its net deferred tax assets as of December 31, 2017. At December 31, 2016, the Company had a valuation allowance totaling $265 million, comprised of $251 million of NOL carryforward limitations under Section 382 of the IRC, $8 million of EOR credits, and $5 million of Canadian NOL carryforwards. These valuation allowances were recorded because the Company determined it was more likely than not that the benefit from these deferred tax assets would not be realized due to the IRC Section 382 limitation on the NOL carryforward and the EOR credit carryforwards, as well as the divestiture of all foreign operations. In 2014, the Company acquired Kodiak Oil & Gas Corp. (“Kodiak”) , which is a Canadian entity that is disregarded for U.S. tax purposes. Kodiak holds an interest in Whiting Resources Corporation, a U.S. entity. Canadian taxes have not been recognized as the tax basis exceeds the book basis in the associated assets. U.S. income taxes on Kodiak and its subsidiary, Whiting Resources Corporation, however, have been fully recognized on their cumulative losses to date. The TCJA provides for a one-time “ deemed repatriation ” of accumulated foreign earnings for the year ended December 31, 2017. We do not expect to pay U.S. federal cash taxes on the deemed repatriation due to an estimated accumulated deficit in foreign earnings for tax purposes. As of December 31, 2017 and 2016, the C ompany did not have any uncertain tax positions. During the year ended December 31, 2016, t he Company reversed an unrecognized tax benefit of $170,000 as a result of the IRC Section 382 limitation, which resulted in the Company recording a full valuation allowance on its EOR credits, the underlying asset generating the uncertain tax position . For the years ended December 31, 201 7 , 201 6 and 201 5 , 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 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 201 4 through 201 7 tax years generally remain subject to examination by federal and state tax authorities. Additionally, the Company has Canadian income tax filings which remain subject to examination by the related tax authorities for the 201 2 through 201 7 tax years.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2017
EARNINGS PER SHARE [Abstract]
EARNINGS PER SHARE	11. EARNINGS PER SHARE The reconciliations between basic and diluted loss per share are as follows (in thousands, except per share data):     Year Ended December 31,  2017 2016 2015  Basic Loss Per Share (1)  Net loss attributable to common shareholders $ (1,237,648) $ (1,339,102) $ (2,219,182)  Weighted average shares outstanding 90,683 62,967 48,868  Loss per common share $ (13.65) $ (21.27) $ (45.41)   Diluted Loss Per Share (1)  Adjusted net loss attributable to common shareholders $ (1,237,648) $ (1,339,102) $ (2,219,182)  Weighted average shares outstanding 90,683 62,967 48,868  Loss per common share $ (13.65) $ (21.27) $ (45.41) _____________________ (1) All share and per share numbers have been retroactively adjusted for the 2015 and 2016 periods to reflect the Company’s one-for-four reverse stock split in November 2017, as described in Note 8 to these consolidated financial statements. For the year ended December 31, 2017, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of 509,744 shares of service-based restricted stock, 22,946 shares of market-based restricted stock and 1,083 stock options. In addition, the diluted earnings per share calculation for the year ended December 31, 2017 excludes the effect of 554,580 common shares for stock options that were out-of-the-money and 5,447 shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2017. For the year ended December 31, 2016, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of (i) 10,820,758 shares issuable for convertible notes prior to their conversions under the if-converted method, (ii) 444,646 shares of service-based restricted stock, and (iii) 1,158 stock options. In addition, the diluted earnings per share calculation for the year ended December 31, 2016 excludes the effect of 479,452 common shares for stock options that were out-of-the-money and 92,548 shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2016. 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 129,034 shares of service-based restricted stock and 21,391 stock options. In addition, the diluted earnings per share calculation for the year ended December 31, 2015 excludes the effect of 169,069 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2015 and 128,689 common shares for stock options that were out-of-the-money. Refer to the “Stock-Based Compensation” footnote for further information on the Company’s restricted stock and stock options. As discussed in the “Long-Term Debt” footnote, the Company has the option to settle the 2020 Convertible Senior Notes with cash, shares of common stock or any combination thereof upon conversion. Based on the current conversion price, the entire outstanding principal amount of the 2020 Convertible Senior Notes as of December 31, 2017 would be convertible into approximately 3.6 million shares of the Company’s common stock. However, the Company’s intent is to settle the principal amount of the notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (the “conversion spread”) is considered in the diluted earnings per share computation under the treasury stock method. As of December 31, 2017, 2016 and 2015, the conversion value did not exceed the principal amount of the notes. Accordingly, there was no impact to diluted earnings per share or the related disclosures for those periods.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2017
COMMITMENTS AND CONTINGENCIES [Abstract]
COMMITMENTS AND CONTINGENCIES	1 2 . 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, 201 7 (in thousands):     Payments due by period  2018 2019 2020 2021 2022 Thereafter Total  Non-cancelable leases $ 7,502 $ 6,399 $ 802 $ - $ - $ - $ 14,703  Drilling rig contracts 19,442 300 - - - - 19,742  Pipeline transportation agreements 5,369 5,369 5,369 5,369 5,369 11,481 38,326  Total $ 32,313 $ 12,068 $ 6,171 $ 5,369 $ 5,369 $ 11,481 $ 72,771  Non-cancelable Leases —The Company leases 222,900 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2019, 44,500 square feet of office space in Midland, Texas expiring in 2020 , and 36,500 square feet of office space in Dickinson, North Dakota expiring in 20 20 . Rental expense for 201 7 , 201 6 and 201 5 amounted to $8 million, $9 million and $9 million, respectively. Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 201 7 are shown in the table above. The Company has sublet the majority of its office space in Midland, Texas to a third party for the remaining lease term. The offsetting rental income has not been included in the table above. Drilling Rig Contracts —As of December 31, 201 7 , the Company had three drilling rigs under long-term contract s, of which two drilling rigs expire in 2018 and one expires in 2019 . The Company’s minimum drilling commitments under the terms of these contracts as of December 31, 201 7 are shown in the table above. As of December 31, 201 7 , early termination of the se contracts would require termination penalties of $11 million, which would be in lieu of paying the remaining drilling commitments under these contracts. During 201 7 , 201 6 and 201 5 , the Company made payments of $29 million, $31 million and $18 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— T he Company has three pipeline transportation agreements with two different suppliers , expiring in 2022, 2024 and 2025 . Under two of these contracts , the Company has committed to pay fixed monthly reservation fees on dedicated pipelines from its Redtail field for natural gas and NGL transportation capacity, plus a variable charge based on actual transportation volumes. These fixed monthly reservation fees totaling approximately $ 38 million have been included in the table above. The remaining contract contains a commitment to transport a minimum volume of crude oil via a certain oil gathering system or else pay for any deficiencies at a price stipulated in the contract. Although minimum annual quantities are specified in the agreement, the actual oil volumes transported 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, 201 7 , the Company estimated the minimum future commitments under this transportation agreement to approximate $17 million through 2022. During 201 7 , 201 6 and 201 5 , transportation of crude oil, natural gas and NGLs under these contracts amounted to $7 million, $5 million and $3 million, respectively. Purchase Contracts —The Company has one take-or-pay purchase agreement which expires in 2020 , whereby the Company has committed to buy certain volumes of water for use in the fracture stimulation process of wells the Company completes in its Redtail field. Under the terms of the agreement, the Company is obligated to purchase a minimum volume of water or else pay for any deficiencies at the price stipulated in the contract. Although minimum daily quantities are specified in the agreement, the actual water volumes purchased 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, 201 7 , the Company estimated the minimum future commitments under this purchase agreement to approximate $23 million through 2020. As a result of the Company’s reduced development operations at its Redtail field, Whiting expects to make periodic deficiency payments under this contract during the remaining term. During 201 7 and 201 6, purchases of water amounted to $22 million and $1 million, respectivel y, which included insignificant deficiency payments for the year ended December 31, 2017 . Water Disposal Agreement —The Company has one water disposal agreement which expires in 2024, whereby it has contracted for the transportation and disposal of the produced water from its 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. Although minimum monthly quantities are specifi ed in the agreement , 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, 201 7 , the Company estimated the minimum future commitments under this disposal agreement to approximate $122 m illion through 2024. As a result of the Company’s reduced development operations at its Redtail field, Whiting has made and expects to make periodic deficiency payments under this contract. During 2017 and 2016, transportation and disposal of produced water amounted to $16 and $8 million, respectively, which includes $4 million and $2 million of deficiency payments, respectively. There were no water disposal costs incurred under this contract during 2015. Delivery Commitments —The Company has various physical delivery contracts which require the Company to deliver fixed volumes of crude oil. One of these delivery commitments became effective on June 1, 2017 upon completion of the Dakota Access Pipeline, and it is tied to crude oil production from Whiting’s Sanish field in Mountrail County, North Dakota . Under the terms of the agreement, Whiting has committed to deliver 15 MBbl/d for a term of seven years. The Company believes its production and reserves at the Sanish field are sufficient to fulfill th is delivery commitment , and therefore expects to avoid any payments for deficiencies under this contract . The remaining two delivery contracts are tied to crude oil production at Whiting’s Redtail field in Weld County, Colorado. On February 1, 2018, the Company paid $61 million to the counterparty to one of these contracts to settle all future minimum volume commitments under the agreement. As of December 31, 201 7 , these contracts contain remaining delivery commitments of 14.8 MMBbl, 16.0 MMBbl and 4.1 MMBbl of crude oil for the years ended December 31, 201 8 through 2020, respectively , which commitments have been reduced to reflect the contract settlement on February 1, 2018 . The Company has determined that it is not probable that future oil production from its Redtail field will be sufficient to meet the minimum volum e requirements specified in these physical delivery contract s , and as a result, the Company expects to make periodic deficiency payments for any shortfalls in delivering the minimum committed volumes. During 2017, 2016 and 2015, total deficiency payments under these contracts amounted to $66 million, $43 million and $15 million , respectively . 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, 201 7 or 201 6 .

CAPITALIZED EXPLORATORY WELL CO

CAPITALIZED EXPLORATORY WELL COSTS	12 Months Ended
	Dec. 31, 2017
CAPITALIZED EXPLORATORY WELL COSTS [Abstract]
CAPITALIZED EXPLORATORY WELL COSTS	1 3 . CAPITALIZED EXPLORATORY WELL COSTS 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,  2017 2016 2015  Beginning balance at January 1 $ - $ - $ 14,293  Additions to capitalized exploratory well costs pending the determination of proved reserves 13,894 - 54,707  Reclassifications to wells, facilities and equipment based on the determination of proved reserves - - (63,352)  Capitalized exploratory well costs charged to expense - - (5,648)  Ending balance at December 31 $ 13,894 $ - $ -  At December 31, 201 7 , the Company had no costs capitalized for exploratory wells in progress for a period of greater than one year after the completion of drilling.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2017
SUBSEQUENT EVENTS [Abstract]
SUBSEQUENT EVENTS	1 4 . SUBSEQUENT EVENTS Redemption of 2019 Senior Notes —On December 27, 2017, the trustee under the indenture governing the Company’s 2019 Senior Notes provided notice to the holders of such notes that Whiting elected to redeem all of the remaining $961 million aggregate principal amount of the 2019 Senior Notes on January 26, 2018, and on that date, Whiting paid $1.0 billion consisting of the 102.976% redemption price plus all accrued and unpaid interest on the notes. The Company financed the redemption with proceeds from the issuance of the 2026 Senior Notes and borrowings under its credit agreement. Termination of Redtail Delivery Commitment —On February 1, 2018, the Company paid $61 million to the counterparty to one of its physical delivery contracts for crude oil production at its Redtail field in Weld County, Colorado to settle all future minimum commitments under this agreement. Refer to the “Commitments and Contingencies” footnote for further information on the Company’s delivery commitments.

SUMMARY OF SIGNIFICANT ACCOUN24

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2017
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
Basis of Presentation of Consolidated Financial Statements	Basis of Presentation of Consolidated Financial Statements —The consolidated financial statements have been prepared in accordance with GAAP and SEC rules and regulations and 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 GAAP 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 (i) oil and natural gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with business combinations, including the determination of any resulting goodwill; (vi) valuations of the Company’s reporting unit used in impairment tests of goodwill; (vii) income taxes; (viii) accrued liabilities; (ix) valuation of derivative instruments; and (x) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.
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.
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash —Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less. Restricted cash at December 31, 2016 relate d to a deposit received in connection with the sale of Whiting’s interests in the Robinson Lake and Belfield gas processing plants. The use of these funds was restricted per the terms of the purchase agreement until the sale transaction closed on January 1, 2017. Refer to the “Acquisition and Divestitures” footnote for further information on this transaction. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and the consolidated statements of cash flows:     December 31,  2017 2016  Cash and cash equivalents $ 879,379 $ 55,975  Restricted cash - 17,250  Total cash, cash equivalents and restricted cash $ 879,379 $ 73,225 
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, 2017 and 2016, the Company had an allowance for doubtful accounts of $17 million and $10 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 and totaled $24 million and $33 million as of December 31, 2017 and 2016, respectively. Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or net realizable value. Oil in tanks is included in prepaid expenses and other and totaled $7 million and $8 million as of December 31, 2017 and 2016, respectively.
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 totaled $83 5 m illion and $1.6 billion for the year s ended December 31, 201 7 and 2015, respectively , which 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 2017, 2016 and 2015, the Company capitalized interest of $0.1 million, $0.1 million and $4 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 totaled $59 million, $73 million and $135 million for the years ended December 31, 2017, 2016 and 2015, respectively, which 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 s incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (i) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (ii) 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.
Other Property and Equipment	Other Property and Equipment — Other property and equipment consists of materials and supplies inventories, carried at weighted-average cost, and 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 business combinations. 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. 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.
Debt Discount and Premiums	Debt Discounts and Premiums —Debt discounts and premiums related to the Company’s senior notes and convertible notes are included as a deduction from or addition to the carrying amount of the 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 notes.
Derivative Instruments	Derivative Instruments —The Company enters into derivative contracts, primarily costless collars and swaps, to manage its exposure to commodity price risk. Whiting follows FASB ASC Topic 815, Derivatives and Hedging , to account for its derivative financial instruments. 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. The Company does not currently apply hedge accounting to any of its outstanding derivative instruments, and as a result, all changes in derivative fair values are recognized currently in 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. Refer to the “Derivative Financial Instruments” footnote for further information.
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 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 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 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, and such revisions 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 18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the unit-of-production method.
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, 2017 and 2016 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.
Stock-based Compensation Expense	Stock-based Compensation Expense —The Company has share-based employee compensation plans that provide for the issuance of various types of stock-based awards, including shares of restricted stock , restricted stock units and stock option s, to employees and non-employee directors. The Company determines compensation expense for restricted stock awards and options granted under these plans based on the grant date fair value , and such expense is recognized on a straight-line basis over the requisite service period of the award. The Company determines compensation expense for cash-settled restricted stock units granted under these plans based on the fair value of such awards at the end of each reporting period, and such awards are recorded as a liability in the consolidated balance sheets . Gains and losses from changes in the fair value of restricted stock units are recognized immediately in earnings . The Company accounts for forfeitures of share-based awards as they occur. Refer to the “Stock-Based Compensation” footnote for further information.
401 (k) Plan	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 2017, 2016 and 2015 were $8 million, $8 million and $12 million, respectively. Employees vest in employer contributions at 20% per year of completed service.
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 attributable 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 attributable 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 to be settled in cash, all using the treasury stock method. In addition, the diluted earnings per share calculation for the year ended December 31, 2016 considers the effect of convertible debt issued and converted during 2016, using the if-converted method for periods prior to their actual conversions. When a loss from continuing operations exists, all dilutive securities and 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. The following tables present 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, 201 7 and 201 6 . 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.  Year Ended December 31, 2017  Tesoro Crude Oil Co 18%    Year Ended December 31, 2016  Tesoro Crude Oil Co 15%  Jamex Marketing LLC 12%  Commodity derivative contracts held by the Company are with nine 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’s. As of December 31, 2017, outstanding derivative contracts with JP Morgan Chase Bank, N.A. , Wells Fargo Bank, N.A. , Capital One, N.A. and KeyBank, N.A. represented 24%, 17% , 14% and 10% , respectively, of total crude oil volumes hedged.
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. The FASB subsequently issued various ASUs which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. ASU 2014-09 and its amendments are 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 adopt ed these ASUs effective January 1, 2018 using the modified retrospective approach. The Company has completed the assessment of its contracts with customers and is in the process of implementing the changes to its financial statements, accounting policies and internal controls as a result of the adoption of these standards. The adoption is not expected to have a n impact on the Company’s net income or cash flows, however, it will result in changes to the classification of fees incurred under certain pipeline gathering and transportation agreements and gas processing agreements , as well as certain costs attributable to non-operated properties, which will result in an overall decrease in total revenues with a corresponding decrease in lease operating expenses under the new standards. In addition, the Company is continuing to assess the additional disclosures that will be required upon implementation of these ASUs. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (“ASU 2016-02”). The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be applied using a modified retrospective approach. Early adoption is permitted. Although the Company is still in the process of evaluating the effect of adopting ASU 2016 ‑02, the adoption is expected to result in (i) an increase in the assets and liabilities recorded on its consolidated balance sheet, (ii) an increase in depreciation, depletion and amortization expense and interest expense recorded on its consolidated statement of operations, and (iii) additional disclosures. As of December 31, 2017, the Company had approximately $ 73 million of contractual obligations related to its non-cancelable leases, drilling rig contracts and pipeline transportation agreements, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASU 2016-02. In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The objective of this ASU is to simplify several aspects of the accounting for employee share-based payment transactions, including income tax consequences, forfeitures, classification of awards as either equity or liabilities and classification in the statement of cash flows. Portions of this ASU must be applied prospectively while other portions may be applied either prospectively or retrospectively. ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, and the Company adopted this standard on January 1, 2017. Upon adoption of ASU 2016-09, the Company (i) recorded previously unrecognized excess tax benefits on a modified retrospective basis with a full valuation allowance, resulting in a net cumulative-effect adjustment to retained earnings of zero , (ii) prospectively removed excess tax benefits from its calculation of diluted shares, which had no impact on the Company’s diluted earnings per share for year ended December 31, 2017, and (iii) elected to account for forfeitures of share-based awards as they occur, rather than by applying an estimated forfeiture rate to determine compensation expense, the effect of which was recognized using a modified retrospective approach and resulted in an immaterial cumulative-effect adjustment to retained earnings and additional paid-in capital.

SUMMARY OF SIGNIFICANT ACCOUN25

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2017
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
Reconciliation Of Cash, Cash Equivalents And Restricted Cash	   December 31,  2017 2016  Cash and cash equivalents $ 879,379 $ 55,975  Restricted cash - 17,250  Total cash, cash equivalents and restricted cash $ 879,379 $ 73,225 
Percentages of total oil and gas sales to significant purchasers	  Year Ended December 31, 2017  Tesoro Crude Oil Co 18%    Year Ended December 31, 2016  Tesoro Crude Oil Co 15%  Jamex Marketing LLC 12% 

OIL AND GAS PROPERTIES (Tables)

OIL AND GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2017
OIL AND GAS PROPERTIES [Abstract]
Net capitalized costs related to oil and gas producing activities	   December 31,  2017 2016  Proved leasehold costs $ 2,622,576 $ 3,330,928  Unproved leasehold costs 137,694 392,484  Costs of completed wells and facilities 8,288,591 9,016,472  Wells and facilities in progress 244,789 490,967  Total oil and gas properties, successful efforts method 11,293,650 13,230,851  Accumulated depletion (4,185,301) (4,170,237)  Oil and gas properties, net $ 7,108,349 $ 9,060,614 

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2017
ACQUISITIONS AND DIVESTITURES [Abstract]
Components of assets and liabilities classified as held for sale	   Carrying Value as of  December 31, 2016  Assets  Oil and gas properties, net $ 347,817  Other property and equipment, net 475  Total property and equipment, net 348,292  Other long-term assets 854  Total assets held for sale $ 349,146   Liabilities  Asset retirement obligations $ 131  Other long-term liabilities 407  Total liabilities related to assets held for sale $ 538 

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2017
LONG-TERM DEBT [Abstract]
Schedule of long-term debt	   December 31,  2017 2016  Credit agreement $ - $ 550,000  6.5% Senior Subordinated Notes due 2018 - 275,121  5.0% Senior Notes due 2019 961,409 961,409  1.25% Convertible Senior Notes due 2020 562,075 562,075  5.75% Senior Notes due 2021 873,609 873,609  6.25% Senior Notes due 2023 408,296 408,296  6.625% Senior Notes due 2026 1,000,000 -  Total principal 3,805,389 3,630,510  Unamortized debt discounts and premiums (50,945) (71,340)  Unamortized debt issuance costs on notes (31,015) (23,867)  Total debt 3,723,429 3,535,303  Less current portion of long-term debt (958,713) -  Total long-term debt $ 2,764,716 $ 3,535,303 
Schedule of five succeeding fiscal years of scheduled maturities for the Company's long-term debt	  2018 2019 2020 2021 2022  Long-term debt $ 961,409 $ - $ 562,075 $ 873,609 $ - 
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 1.00% 2.00% 0.50%  Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 1.25% 2.25% 0.50%  Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 1.50% 2.50% 0.50%  Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 1.75% 2.75% 0.50%  Greater than or equal to 0.90 to 1.0 2.00% 3.00% 0.50% 
Summary of senior notes and convertible senior notes	    2020  2019 Convertible 2021 2023 2026  Senior Notes (1) Senior Notes Senior Notes Senior Notes Senior Notes  Outstanding principal (in thousands) $ 961,409 $ 562,075 $ 873,609 $ 408,296 $ 1,000,000  Interest rate 5.0% 1.25% 5.75% 6.25% 6.625%  Maturity date Mar 15, 2019 Apr 1, 2020 Mar 15, 2021 Apr 1, 2023 Jan 15, 2026  Interest payment dates Mar 15, Sep 15 Apr 1, Oct 1 Mar 15, Sep 15 Apr 1, Oct 1 Jan 15, Jul 15  Make-whole redemption date (2) Dec 15, 2018 N/A (3) Dec 15, 2020 Jan 1, 2023 Oct 15, 2025 _____________________ (1) On January 26, 2018, the Company used the proceeds from the December 2017 issuance of its 6.625% Senior Notes due January 2026 as well as borrowings under its credit agreement to redeem all of the outstanding 5.0% Senior Notes due March 2019. (2) On or after these dates, the Company may redeem the applicable series of notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. At any time prior to these dates, the Company may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes. (3) The indenture governing the 1.25% Convertible Senior Notes due 2020 does not allow for optional redemption by the Company prior to the maturity date.
Schedule of convertible senior notes	    December 31,  2017 2016  Liability component  Principal $ 562,075 $ 562,075  Less: unamortized note discount (51,666) (72,622)  Less: unamortized debt issuance costs (4,178) (5,988)  Net carrying value $ 506,231 $ 483,465  Equity component (1) $ 136,522 $ 136,522 (1) Recorded in additional paid-in capital, net of $5 million of issuance costs and $50 million of deferred taxes as of December 31, 2017 and 2016.

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2017
ASSET RETIREMENT OBLIGATIONS [Abstract]
Schedule of reconciliation of the Company's asset retirement obligations	    2017 2016  Asset retirement obligation at January 1 $ 177,004 $ 161,908  Additional liability incurred 7,727 3,238  Revisions to estimated cash flows (1) (2) (52,947) 11,620  Accretion expense 13,809 13,800  Obligations on sold properties (6,988) (4,771)  Liabilities settled (4,368) (8,791)  Asset retirement obligation at December 31 $ 134,237 $ 177,004 (1) Revisions to estimated cash flows during the year ended December 31, 2017 are primarily attributable to the deferral of the estimated timing of abandonment of a large number of Whiting’s producing properties resulting from in creases in commodity prices used in the calculation of the Company’s reserves as of December 31, 2017 , which lengthened the economic lives of these properties. In addition, during 2017 there were decreases in the estimates of future costs required to plug and abandon wells in certain fields in the Northern Rocky Mountains. (2) R evisions to estimated cash flows during the year ended December 31, 2016 are primarily attributable to the a cceleration in the estimated timing of abandonment of a large number of Whiting’s producing properties resulting from de creases in commodity prices used in the calculation of the Company’s reserves as of December 31, 201 6, which shortened the economic lives of these properties . For the year ended December 31, 2016, the increase was partially offset by decreases in the estimates of future costs required to plug and abandon wells in certain fields in the Central and Northern Rocky Mountains.

DERIVATIVE FINANCIAL INSTRUME30

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Financial Instruments [Line Items]
Schedule of effects of commodity derivative instruments	      (Gain) Loss Recognized in Income  Not Designated as Statement of Operations Year Ended December 31,  ASC 815 Hedges Classification 2017 2016 2015  Commodity contracts Derivative (gain) loss, net $ 104,138 $ 58,771 $ (217,972)  Embedded derivatives Derivative (gain) loss, net 18,709 (59,358) -  Total $ 122,847 $ (587) $ (217,972) 
Location and fair value of derivative instruments	    December 31, 2017 (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 Prepaid expenses and other $ 9,829 $ (9,829) $ -  Total derivative assets $ 9,829 $ (9,829) $ -  Derivative liabilities  Commodity contracts - current Derivative liabilities $ 142,354 $ (9,829) $ 132,525  Total derivative liabilities $ 142,354 $ (9,829) $ 132,525      December 31, 2016 (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 Prepaid expenses and other $ 21,405 $ (21,405) $ -  Commodity contracts - non-current Other long-term assets 9,495 (9,495) -  Embedded derivatives - non-current Other long-term assets 50,632 - 50,632  Total derivative assets $ 81,532 $ (30,900) $ 50,632  Derivative liabilities  Commodity contracts - current Derivative liabilities $ 39,033 $ (21,405) $ 17,628  Commodity contracts - non-current Other long-term liabilities 19,724 (9,495) 10,229  Total derivative liabilities $ 58,757 $ (30,900) $ 27,857 _____________________ (1) Because counterparties to the Company’s financial derivative contracts subject to master netting arrangements 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 these tables.
Whiting Petroleum Corporation [Member]
Derivative Financial Instruments [Line Items]
Derivative instruments	     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 2018 17,400,000 $37.07 - $47.07 - $57.30  Total 17,400,000 _____________________ (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. (2) Subsequent to December 31, 2017 , the Company entered into additional swap contracts for 4,400,000 Bbl of crude oil volumes for the year ended December 31, 2018 , as well as costless collars for 900,000 Bbl of crude oil volumes for the six months ended June 30, 2019 .

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2017
FAIR VALUE MEASUREMENTS [Abstract]
Summary of the fair values and carrying value of debt instruments	    December 31, 2017 December 31, 2016  Fair Carrying Fair Carrying  Value (1) Value (2) Value (1) Value (2)  6.5% Senior Subordinated Notes due 2018 $ - $ - $ 275,121 $ 273,506  5.0% Senior Notes due 2019 985,444 958,713 961,409 956,607  1.25% Convertible Senior Notes due 2020 517,109 506,231 503,057 483,465  5.75% Senior Notes due 2021 897,633 869,284 868,149 868,460  6.25% Senior Notes due 2023 418,503 403,940 408,296 403,265  6.625% Senior Notes due 2026 1,025,000 985,261 - -  Total $ 3,843,689 $ 3,723,429 $ 3,016,032 $ 2,985,303 (1) 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. (2) Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums.
Fair value assets and liabilities measured on a recurring basis	   Total Fair Value  Level 1 Level 2 Level 3 December 31, 2017  Financial Liabilities  Commodity derivatives – current $ - $ 69,247 $ 63,278 $ 132,525  Total financial liabilities $ - $ 69,247 $ 63,278 $ 132,525      Total Fair Value  Level 1 Level 2 Level 3 December 31, 2016  Financial Assets  Embedded derivatives – non-current $ - $ 50,632 $ - $ 50,632  Total financial assets $ - $ 50,632 $ - $ 50,632  Financial Liabilities  Commodity derivatives – current $ - $ 14,664 $ 2,964 $ 17,628  Commodity derivatives – non-current - 3,979 6,250 10,229  Total financial liabilities $ - $ 18,643 $ 9,214 $ 27,857 
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy	     Year Ended December 31,  2017 2016  Fair value liability, beginning of period $ (9,214) $ (4,027)  Recognition of embedded derivatives associated with convertible note issuances - (89,884)  Unrealized gains on embedded derivatives included in earnings (1) - 47,965  Settlement of embedded derivatives upon conversion of convertible notes - 41,919  Unrealized losses on commodity derivative contracts included in earnings (1) (54,064) (5,187)  Transfers into (out of) Level 3 - -  Fair value liability, end of period $ (63,278) $ (9,214) _____________________ (1) Included in derivative ( gain ) loss , net in the consolidated statements of operations.
Significant unobservable inputs used in the fair value measurement	   Derivative Instrument Valuation Technique Unobservable Input Amount  Commodity derivative contract Probability-weighted i ncome approach Market differential for crude oil $4.08 - $4.92 per Bbl 
Non-financial assets and liabilities measured at fair value on a nonrecurring basis	   Loss (Before  Net Carrying Tax) Year  Value as of Ended  December 31, Fair Value Measurements Using December 31,  2017 Level 1 Level 2 Level 3 2017  Proved property (1) $ 389,390 $ - $ - $ 389,390 $ 834,950 _____________________ (1) During the fourth quarter of 2017, proved oil and gas properties at the Redtail field in the Denver Julesburg Basin (the “ DJ Basin ”) in Weld County, Colorado, with a previous carrying amount of $1.2 billion were written down to their fair value as of December 31, 2017 of $ 389 million, resulting in a non-cash impairment charge of $ 835 m illion which was recorded within exploration and impairment expense.

SHAREHOLDERS_ EQUITY AND NONC32

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST (Tables)	12 Months Ended
	Dec. 31, 2017
SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST [Abstract]
Schedule of noncontrolling interest	   Year Ended December 31,  2017 2016  Balance at beginning of period $ 7,962 $ 7,984  Net loss (14) (22)  Conveyance of ownership interest (7,948) -  Balance at end of period $ - $ 7,962 

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2017
STOCK-BASED COMPENSATION [Abstract]
Assumption for valuing market based restricted shares	  2017 2016 2015  Number of simulations 2,500,000 2,500,000 2,500,000  Expected volatility 82.44% 60.8% 40.3%  Risk-free interest rate 1.52% 1.13% 0.99%  Dividend yield - - - 
Summary of nonvested restricted stock	    Number of Awards Weighted Average  Service-Based Service-Based Market-Based Grant Date  RSAs RSUs Performance Awards Fair Value  Nonvested awards, January 1 766,818 - 523,172 $ 54.19  Granted 538,194 39,619 168,466 44.89  Vested (339,199) - - 51.23  Forfeited (67,392) - (194,111) 81.97  Nonvested awards, December 31 898,421 39,619 497,527 $ 44.99 
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 1 128,524 $ 158.17  Granted - -  Exercised - - $ -  Forfeited or expired (6,490) 207.86  Options outstanding at December 31 122,034 $ 154.32 $ 28 2.4  Options vested at December 31 122,034 $ 154.32 $ 28 2.4  Options exercisable at December 31 122,034 $ 154.32 $ 28 2.4 

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2017
INCOME TAXES [Abstract]
Schedule of income tax expense	   Year Ended December 31,  2017 2016 2015  Current income tax expense (benefit)  Federal $ (7,305) $ (7,340) $ -  State 14 150 (357)  Total current income tax benefit (7,291) (7,190) (357)  Deferred income tax benefit  Federal (398,686) (65,130) (736,520)  State (77,002) (15,326) (37,350)  Total deferred income tax benefit (475,688) (80,456) (773,870)  Total $ (482,979) $ (87,646) $ (774,227) 
Reconciliation of statutory income tax expense to income tax expense	   Year Ended December 31,  2017 2016 2015  U.S. statutory income tax benefit $ (602,219) $ (499,370) $ (1,047,723)  State income taxes, net of federal benefit (39,557) (33,050) (44,654)  Valuation allowance 120,880 - -  Federal tax reform (42,033) - -  Impairment charge after enactment of federal tax reform 114,293 - -  IRC Section 382 limitation (45,899) 259,494 -  Non-deductible convertible debt expenses - 174,071 -  Goodwill impairment - - 305,820  Market-based equity awards 7,003 8,352 2,690  Enacted changes in state tax laws - 5,020 7,350  Other 4,553 (2,163) 2,290  Total $ (482,979) $ (87,646) $ (774,227) 
Components of deferred income tax assets and liabilities	   Year Ended December 31,  2017 2016  Deferred income tax assets  Net operating loss carryforward $ 828,617 $ 1,248,034  Derivative instruments 31,567 6,145  Asset retirement obligations 16,138 21,398  Restricted stock compensation 9,704 12,171  EOR credit carryforwards 7,946 7,946  Alternative minimum tax credit carryforwards - 7,847  Other 11,549 19,356  Total deferred income tax assets 905,521 1,322,897  Less valuation allowance (271,300) (264,461)  Net deferred income tax assets 634,221 1,058,436  Deferred income tax liabilities  Oil and gas properties 566,747 1,412,781  Trust distributions 54,980 94,120  Discount on convertible senior notes 12,494 27,224  Total deferred income tax liabilities 634,221 1,534,125  Total net deferred income tax liabilities $ - $ 475,689 

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2017
EARNINGS PER SHARE [Abstract]
Reconciliations between basic and diluted earnings per share	     Year Ended December 31,  2017 2016 2015  Basic Loss Per Share (1)  Net loss attributable to common shareholders $ (1,237,648) $ (1,339,102) $ (2,219,182)  Weighted average shares outstanding 90,683 62,967 48,868  Loss per common share $ (13.65) $ (21.27) $ (45.41)   Diluted Loss Per Share (1)  Adjusted net loss attributable to common shareholders $ (1,237,648) $ (1,339,102) $ (2,219,182)  Weighted average shares outstanding 90,683 62,967 48,868  Loss per common share $ (13.65) $ (21.27) $ (45.41) _____________________ (1) All share and per share numbers have been retroactively adjusted for the 2015 and 2016 periods to reflect the Company’s one-for-four reverse stock split in November 2017, as described in Note 8 to these consolidated financial statements.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2017
COMMITMENTS AND CONTINGENCIES [Abstract]
Minimum future payments under non-cancelable operating leases and unconditional purchase obligations	   Payments due by period  2018 2019 2020 2021 2022 Thereafter Total  Non-cancelable leases $ 7,502 $ 6,399 $ 802 $ - $ - $ - $ 14,703  Drilling rig contracts 19,442 300 - - - - 19,742  Pipeline transportation agreements 5,369 5,369 5,369 5,369 5,369 11,481 38,326  Total $ 32,313 $ 12,068 $ 6,171 $ 5,369 $ 5,369 $ 11,481 $ 72,771 

CAPITALIZED EXPLORATORY WELL 37

CAPITALIZED EXPLORATORY WELL COSTS (Tables)	12 Months Ended
	Dec. 31, 2017
CAPITALIZED EXPLORATORY WELL COSTS [Abstract]
Net changes in capitalized exploratory well costs	   Year Ended December 31,  2017 2016 2015  Beginning balance at January 1 $ - $ - $ 14,293  Additions to capitalized exploratory well costs pending the determination of proved reserves 13,894 - 54,707  Reclassifications to wells, facilities and equipment based on the determination of proved reserves - - (63,352)  Capitalized exploratory well costs charged to expense - - (5,648)  Ending balance at December 31 $ 13,894 $ - $ - 

SUMMARY OF SIGNIFICANT ACCOUN38

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative I) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary Of Significant Accounting Policies [Line Items]
Oil and gas receivables collection period	2 months
Allowance for doubtful account	$ 17,000	$ 10,000
Materials and supplies inventories	24,000	33,000
Oil in tanks	7,000	8,000
Impairment of Proved Properties	835,000		$ 1,600,000
Impairment of Unproved Properties	59,000	73,000	135,000
Interest cost capitalized	$ 100	$ 100	4,000
Goodwill			$ 0
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	P4Y
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life	P30Y

SUMMARY OF SIGNIFICANT ACCOUN39

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative II) (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)segmentitem$ / shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)	Jan. 01, 2017USD ($)
Summary Of Significant Accounting Policies [Line Items]
Employer's contribution in employees retirement plan	$ 8,000	$ 8,000	$ 12,000
Employees vest in employer contribution Percentage, per year of completed service		20.00%
Number of operating segments | segment	1
Contractual obligation	$ 72,771
Accounting Standards Update 2016-09 [Member]
Summary Of Significant Accounting Policies [Line Items]
New accounting pronouncement, cumulative effect of change on equity				$ 0
New accounting pronouncement, impact on diluted earnings per share | $ / shares	$ 0
Whiting USA Trust II Units [Member]
Summary Of Significant Accounting Policies [Line Items]
Trust units sold to the public (in shares) | shares		18,400,000
Commodity Price Risk [Member] | Derivative Contracts [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of counterparties | item	9
JP Morgan Chase [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member]
Summary Of Significant Accounting Policies [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged	24.00%
Wells Fargo Bank [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member]
Summary Of Significant Accounting Policies [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged	17.00%
Capital One, N. A. [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member]
Summary Of Significant Accounting Policies [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged	14.00%
KeyBank, N.A. [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member]
Summary Of Significant Accounting Policies [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged	10.00%

SUMMARY OF SIGNIFICANT ACCOUN40

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reconciliation Of Cash, Cash Equivalents And Restricted Cash) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
Cash and cash equivalents	$ 879,379	$ 55,975
Restricted cash		17,250
Total cash, cash equivalents and restricted cash	$ 879,379	$ 73,225	$ 16,053	$ 78,100

SUMMARY OF SIGNIFICANT ACCOUN41

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, 2017	Dec. 31, 2016
Tesoro Crude Oil Co [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	18.00%	15.00%
Jamex Marketing LLC [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue		12.00%

OIL AND GAS PROPERTIES (Details

OIL AND GAS PROPERTIES (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
OIL AND GAS PROPERTIES [Abstract]
Proved leasehold costs	$ 2,622,576	$ 3,330,928
Unproved leasehold costs	137,694	392,484
Costs of completed wells and facilities	8,288,591	9,016,472
Wells and facilities in progress	244,789	490,967
Total oil and gas properties, successful efforts method	11,293,650	13,230,851
Accumulated depletion	(4,185,301)	(4,170,237)
Oil and gas properties, net	$ 7,108,349	$ 9,060,614

ACQUISITIONS AND DIVESTITURES43

ACQUISITIONS AND DIVESTITURES (Narrative) (Details)	Sep. 01, 2017USD ($)	Jul. 19, 2017USD ($)	Jan. 01, 2017USD ($)	Jun. 01, 2015USD ($)stateitem	May 01, 2015USD ($)stateitem	Jul. 31, 2016USD ($)$ / bbl	Dec. 31, 2015USD ($)	Dec. 31, 2015USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale	$ 500,000,000		$ 375,000,000	$ 150,000,000	$ 108,000,000	$ 300,000,000	$ 75,000,000
Gain (loss) on sale	$ (402,000,000)	$ 3,000,000		$ (118,000,000)	$ 29,000,000	(187,000,000)
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
Additional proceeds from disposal for specified period for each $0.01 average NYMEX futures is above threshold price per Bbl						$ 100,000
Average price per Bbl threshold for additional proceeds from sale | $ / bbl						50
Maximum possible additional proceeds from divestiture of business						$ 100,000,000
Amount received from settled contingent payment		$ 35,000,000
Robinson Lake Gas Processing Plant [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of interest in gas processing plant			50.00%
Belfield Gas Processing Plant [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of interest in gas processing plant			50.00%
Non-Core Producing Oil And Gas Wells And Undeveloped Acreage [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale								$ 176,000,000
Gain (loss) on sale								$ 28,000,000

ACQUISITIONS AND DIVESTITURES44

ACQUISITIONS AND DIVESTITURES (Components of Assets and Liabilities Classified As Held For Sale) (Details) $ in Thousands	Dec. 31, 2016USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total assets held for sale	$ 349,146
Total liabilities related to assets held for sale	538
Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and gas properties, net	347,817
Other property and equipment, net	475
Total property and equipment, net	348,292
Other long-term assets	854
Total assets held for sale	349,146
Asset retirement obligations	131
Other long-term liabilities	407
Total liabilities related to assets held for sale	$ 538

LONG-TERM DEBT (Credit agreemen

LONG-TERM DEBT (Credit agreement) (Details) - Whiting Oil and Gas Corporation [Member] - Credit Agreement [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)	Oct. 01, 2017USD ($)	Dec. 31, 2016
Debt Instrument [Line Items]
Maximum borrowing capacity of credit facility	$ 2,300,000	$ 2,500,000
Maximum aggregate commitments	2,300,000	$ 2,500,000
Borrowing capacity of credit facility, net of letter of credit	2,300,000
Outstanding borrowings under credit facility	0
Letters of credit borrowings outstanding	2,000
Portion of line of credit available for issuance of letters of credit	50,000
Amount of revolving credit agreement available for additional letters of credit under the agreement	48,000
Weighted average interest rate			4.00%
Permitted issuance of second lien indebtedness maximum amount	1,000,000
Retained earnings free from restrictions	$ 0
Minimum consolidated current assets to consolidated current liabilities ratio	1
Total senior secured debt to EBITDAX ratio	3
EBITDAX to consolidated interest charges	2.25
Base Rate [Member]
Debt Instrument [Line Items]
Variable interest rate basis	federal funds
Basis points added to reference rate (as a percent)	0.50%
LIBOR [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Basis points added to reference rate (as a percent)	1.00%
April 1, 2018 Or Commencement Of An Investment-Grade Debt Rating Period [Member]
Debt Instrument [Line Items]
Total debt to EBITDAX ratio	4

LONG-TERM DEBT (Senior notes an

LONG-TERM DEBT (Senior notes and senior subordinated notes) (Details) - USD ($) shares in Millions	Jan. 26, 2018	Feb. 02, 2017	Jul. 01, 2016	Mar. 23, 2016	Dec. 24, 2015	May 01, 2015	Mar. 06, 2015	Jan. 07, 2015	Jul. 31, 2016	Jun. 30, 2016	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2017	Mar. 31, 2015	Dec. 08, 2014	Sep. 30, 2013	Sep. 26, 2013	Sep. 30, 2010
Debt Instrument [Line Items]
Cash charge related to the redemption premium													$ 41,919,000
Aggregate principal amount exchanged				$ 477,000,000
Non cash charges									$ 113,000,000
Total principal											$ 3,805,389,000		3,630,510,000
Repayment of subordinated notes											275,121,000
Gain (loss) on extinguishment of debt									$ 57,000,000		$ (1,540,000)		$ (42,236,000)	$ (18,361,000)
6.5% Senior Subordinated Notes due 2018 [Member] | Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Notes Issued																				$ 350,000,000
Interest rate on debt instrument (as a percent)											6.50%		6.50%							6.50%
Aggregate principal amount exchanged			$ 26,000,000	49,000,000
Total principal		$ 275,000,000											$ 275,121,000		$ 0
Repayment of subordinated notes		$ 281,000,000
Percentage of redemption price		100.00%
Gain (loss) on extinguishment of debt		$ (2,000,000)
5.0% Senior Notes due 2019 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Notes Issued																		$ 1,100,000,000
Interest rate on debt instrument (as a percent)											5.00%	[1]	5.00%					5.00%
Aggregate principal amount exchanged			42,000,000	97,000,000
Total principal											$ 961,409,000	[1]	$ 961,409,000
Notes repurchased, principal amount	$ 961,000,000
5.75% Senior Notes due 2021 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Notes Issued																		$ 800,000,000	$ 400,000,000
Interest rate on debt instrument (as a percent)											5.75%		5.75%					5.75%	5.75%
Premium as a percentage of par																			101.00%
Debt, effective interest rate											5.50%
Aggregate principal amount exchanged			174,000,000	152,000,000
Total principal											$ 873,609,000		$ 873,609,000
6.25% Senior Notes due 2023 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Notes Issued																$ 750,000,000
Interest rate on debt instrument (as a percent)											6.25%		6.25%	6.25%		6.25%
Aggregate principal amount exchanged			163,000,000	179,000,000
Total principal											$ 408,296,000		$ 408,296,000
6.625% Senior Notes due 2026 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Notes Issued											$ 1,000,000,000
Interest rate on debt instrument (as a percent)											6.625%
Total principal											$ 1,000,000,000
8.125% Senior Notes due 2019 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Notes Issued																	$ 800,000,000
Interest rate on debt instrument (as a percent)														8.125%			8.125%
Repurchase of notes														$ 832,429,000
Notes repurchased, principal amount					$ 798,000,000		$ 2,000,000
5.5% Senior Notes due 2021 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Notes Issued																	$ 350,000,000
Interest rate on debt instrument (as a percent)														5.50%			5.50%
Repurchase of notes														$ 353,500,000
Notes repurchased, principal amount						$ 4,000,000	346,000,000
5.5% Senior Notes due 2022 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Notes Issued																	$ 400,000,000
Interest rate on debt instrument (as a percent)														5.50%			5.50%
Repurchase of notes														$ 404,000,000
Notes repurchased, principal amount						1,000,000	399,000,000
New Convertible Notes [Member]
Debt Instrument [Line Items]
Notes Issued				477,000,000
Non cash charges				4,000,000
Fair value difference from principal amount				95,000,000
Unamortized debt discount				185,000,000
Fair value of embedded derivatives for conversion options				90,000,000
Aggregate principal amount converted into shares										$ 477,000,000
Number of shares upon settlement of conversion										10.5
Total principal										$ 0
Cash paid for early conversion of notes, including accrued and unpaid interest										46,000,000
Gain (loss) on extinguishment of debt				$ 91,000,000						$ (188,000,000)
Senior Subordinated Notes And Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged			$ 405,000,000
Repurchased Kodiak Notes [Member]
Debt Instrument [Line Items]
Total principal														0
Repurchased Kodiak Notes [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Cash charge related to the redemption premium														40,000,000
Non cash charges														22,000,000
Repurchase of notes					$ 834,000,000	$ 5,000,000	$ 760,000,000
Notes repurchased, principal amount								$ 1,550,000,000
Percentage of redemption price					104.063%	101.00%	101.00%	101.00%
Gain (loss) on extinguishment of debt														$ (18,000,000)
Subsequent Event [Member] | 5.0% Senior Notes due 2019 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Repurchase of notes	$ 1,000,000,000
Percentage of redemption price	102.976%
[1]	On January 26, 2018, the Company used the proceeds from the December 2017 issuance of its 6.625% Senior Notes due January 2026 as well as borrowings under its credit agreement to redeem all of the outstanding 5.0% Senior Notes due March 2019.

LONG-TERM DEBT (2020 Convertibl

LONG-TERM DEBT (2020 Convertible senior notes) (Details)	Jul. 01, 2016USD ($)	Jun. 29, 2016USD ($)	Mar. 23, 2016USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2017USD ($)item$ / shares$ / item	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Debt finance cost					$ 31,015,000	$ 23,867,000
Aggregate principal amount exchanged			$ 477,000,000
Interest expense					191,088,000	557,620,000	$ 334,125,000
Convertible Senior Notes [Member] | 1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Principal				$ 1,250,000,000	$ 562,075,000	$ 562,075,000
Interest rate on debt instrument (as a percent)				1.25%	1.25%	1.25%	1.25%
Net proceeds				$ 1,200,000,000
Debt finance cost				25,000,000	$ 4,178,000	$ 5,988,000
Aggregate principal amount exchanged	$ 559,000,000	$ 129,000,000
Principal amount per conversion ratio | $ / item					1,000
Conversion ratio					6.4102
Conversion price per $1,000 principal amount of notes | $ / shares					$ 156
Debt, effective interest rate					5.60%
Estimated fair value of Notes				1,000,000,000
Debt discount				$ 238,000,000	$ 51,666,000	72,622,000
Interest expense					$ 28,000,000	$ 43,000,000	$ 44,000,000
Convertible Senior Notes, Conversion Scenario 1 [Member] | Convertible Senior Notes [Member] | 1.25% Convertible Senior Notes due 2020 [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%
Convertible Senior Notes, Conversion Scenario 2 [Member] | Convertible Senior Notes [Member] | 1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
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%
Debt Instruments Convertible Threshold Consecutive Trading Days					5 days

LONG-TERM DEBT (Mandatory conve

LONG-TERM DEBT (Mandatory convertible notes, security and guarantees) (Details) - USD ($) shares in Millions	Feb. 02, 2017	Jul. 01, 2016	Jun. 29, 2016	Mar. 23, 2016	Jul. 31, 2016	Jul. 31, 2016	Dec. 31, 2016	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2017	Mar. 31, 2015	Sep. 30, 2013	Sep. 26, 2013	Sep. 30, 2010
Debt Instrument [Line Items]
Aggregate principal amount exchanged				$ 477,000,000
Carrying value of debt instrument							$ 3,630,510,000	$ 3,805,389,000		$ 3,630,510,000
Percentage of owned subsidiaries										100.00%
Gain (loss) on extinguishment of debt						$ 57,000,000		(1,540,000)		$ (42,236,000)	$ (18,361,000)
Non cash charges						113,000,000
Adjustment to equity component of 2020 Convertible Senior Notes upon extinguishment, net										(63,330,000)
Senior Notes, 1.25% Convertible Senior Notes due 2020, and Senior Subordinated Notes [Member
Debt Instrument [Line Items]
Aggregate principal amount exchanged		$ 964,000,000
Mandatory Convertible Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount converted into shares							$ 1,093,000,000
Number of shares upon settlement of conversion							28.9
Carrying value of debt instrument							$ 0			0
Gain (loss) on extinguishment of debt							(1,000,000)
Non cash charges							259,000,000
Recognition of beneficial conversion features on convertible notes					$ 233,000,000					232,801,000
Fair value difference from principal amount					69,000,000	69,000,000
Debt discount					$ 302,000,000	$ 302,000,000
Convertible Senior Notes [Member] | 1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged		559,000,000	$ 129,000,000
Principal							562,075,000	562,075,000		562,075,000			$ 1,250,000,000
Carrying value of debt instrument							562,075,000	562,075,000		562,075,000
Adjustment to equity component of 2020 Convertible Senior Notes upon extinguishment, net		(63,000,000)
Debt discount							72,622,000	51,666,000		72,622,000			238,000,000
Convertible Senior Notes [Member] | 1.25% Mandatory Convertible Senior Notes due 2020, Series 2 [Member]
Debt Instrument [Line Items]
Principal			$ 129,000,000
Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged		26,000,000		49,000,000
Principal																$ 350,000,000
Carrying value of debt instrument	$ 275,000,000						275,121,000			275,121,000		$ 0
Gain (loss) on extinguishment of debt	$ (2,000,000)
Senior Notes [Member] | 5.0% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged		42,000,000		97,000,000
Principal														$ 1,100,000,000
Carrying value of debt instrument							961,409,000	961,409,000	[1]	961,409,000
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged		174,000,000		152,000,000
Principal														$ 800,000,000	$ 400,000,000
Carrying value of debt instrument							873,609,000	873,609,000		873,609,000
Senior Notes [Member] | 6.25% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged		$ 163,000,000		$ 179,000,000
Principal													$ 750,000,000
Carrying value of debt instrument							$ 408,296,000	$ 408,296,000		$ 408,296,000
[1]	On January 26, 2018, the Company used the proceeds from the December 2017 issuance of its 6.625% Senior Notes due January 2026 as well as borrowings under its credit agreement to redeem all of the outstanding 5.0% Senior Notes due March 2019.

LONG-TERM DEBT (Schedule of lon

LONG-TERM DEBT (Schedule of long-term debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2017		Mar. 31, 2017	Feb. 02, 2017	Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Sep. 30, 2013	Sep. 26, 2013	Sep. 30, 2010
Debt Instrument [Line Items]
Total principal	$ 3,805,389				$ 3,630,510
Unamortized debt discounts and premiums	(50,945)				(71,340)
Unamortized debt issuance costs on notes	(31,015)				(23,867)
Total debt	3,723,429				3,535,303
Less current portion of long-term debt	(958,713)
Total long-term debt	$ 2,764,716				3,535,303
Credit Agreement [Member]
Debt Instrument [Line Items]
Total principal					550,000
Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member]
Debt Instrument [Line Items]
Total principal			$ 0	$ 275,000	$ 275,121
Interest rate on debt instrument (as a percent)	6.50%				6.50%					6.50%
Senior Notes [Member] | 5.0% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Total principal	$ 961,409	[1]			$ 961,409
Interest rate on debt instrument (as a percent)	5.00%	[1]			5.00%			5.00%
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Total principal	$ 873,609				$ 873,609
Interest rate on debt instrument (as a percent)	5.75%				5.75%			5.75%	5.75%
Senior Notes [Member] | 6.25% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Total principal	$ 408,296				$ 408,296
Interest rate on debt instrument (as a percent)	6.25%				6.25%	6.25%	6.25%
Senior Notes [Member] | 6.625% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Total principal	$ 1,000,000
Interest rate on debt instrument (as a percent)	6.625%
Convertible Senior Notes [Member] | 1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Total principal	$ 562,075				$ 562,075
Unamortized debt issuance costs on notes	$ (4,178)				$ (5,988)		$ (25,000)
Interest rate on debt instrument (as a percent)	1.25%				1.25%	1.25%	1.25%
[1]	On January 26, 2018, the Company used the proceeds from the December 2017 issuance of its 6.625% Senior Notes due January 2026 as well as borrowings under its credit agreement to redeem all of the outstanding 5.0% Senior Notes due March 2019.

LONG-TERM DEBT (Schedule of fiv

LONG-TERM DEBT (Schedule of five succeeding fiscal years of scheduled maturities for the Company's long-term debt) (Details) $ in Thousands	Dec. 31, 2017USD ($)
LONG-TERM DEBT [Abstract]
2,018	$ 961,409
2,020	562,075
2,021	$ 873,609

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, 2017
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)	0.50%
Less than 0.25 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.00%
Less than 0.25 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	2.00%
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)	0.50%
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)	1.25%
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)	2.25%
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)	1.50%
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)	2.50%
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)	1.75%
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)	2.75%
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)	2.00%
Greater than or equal to 0.90 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	3.00%

LONG-TERM DEBT (Summary of seni

LONG-TERM DEBT (Summary of senior notes and convertible senior notes) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Sep. 30, 2013	Sep. 26, 2013
Debt Instrument [Line Items]
Carrying value of debt instrument		$ 3,805,389		$ 3,630,510
Percentage of principal amount redeemable		100.00%
5.0% Senior Notes due 2019 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Carrying value of debt instrument		$ 961,409	[1]	$ 961,409
Interest rate on debt instrument (as a percent)		5.00%	[1]	5.00%			5.00%
Debt maturity date	[1]	Mar. 15, 2019
Interest payment dates	[1]	Mar 15, Sep 15
Make-whole redemption date	[1],[2]	Dec. 15, 2018
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Carrying value of debt instrument		$ 562,075		$ 562,075
Interest rate on debt instrument (as a percent)		1.25%		1.25%	1.25%	1.25%
Debt maturity date		Apr. 1, 2020
Interest payment dates		Apr 1, Oct 1
5.75% Senior Notes due 2021 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Carrying value of debt instrument		$ 873,609		$ 873,609
Interest rate on debt instrument (as a percent)		5.75%		5.75%			5.75%	5.75%
Debt maturity date		Mar. 15, 2021
Interest payment dates		Mar 15, Sep 15
Make-whole redemption date	[2]	Dec. 15, 2020
6.25% Senior Notes due 2023 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Carrying value of debt instrument		$ 408,296		$ 408,296
Interest rate on debt instrument (as a percent)		6.25%		6.25%	6.25%	6.25%
Debt maturity date		Apr. 1, 2023
Interest payment dates		Apr 1, Oct 1
Make-whole redemption date	[2]	Jan. 1, 2023
6.625% Senior Notes due 2026 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Carrying value of debt instrument		$ 1,000,000
Interest rate on debt instrument (as a percent)		6.625%
Debt maturity date		Jan. 15, 2026
Interest payment dates		Jan 15, Jul 15
Make-whole redemption date	[2]	Oct. 15, 2025
[1]	On January 26, 2018, the Company used the proceeds from the December 2017 issuance of its 6.625% Senior Notes due January 2026 as well as borrowings under its credit agreement to redeem all of the outstanding 5.0% Senior Notes due March 2019.
[2]	On or after these dates, the Company may redeem the applicable series of notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. At any time prior to these dates, the Company may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes.

LONG-TERM DEBT (Schedule of con

LONG-TERM DEBT (Schedule of convertible senior notes) (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Mar. 31, 2015
Debt Instrument [Line Items]
Less: unamortized debt issuance costs		$ (31,015,000)	$ (23,867,000)
Convertible Senior Notes [Member] | 1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Principal		562,075,000	562,075,000	$ 1,250,000,000
Less: unamortized note discount		(51,666,000)	(72,622,000)	(238,000,000)
Less: unamortized debt issuance costs		(4,178,000)	(5,988,000)	$ (25,000,000)
Net carrying value		506,231,000	483,465,000
Equity component	[1]	136,522,000	136,522,000
Convertible Senior Notes [Member] | 1.25% Convertible Senior Notes due 2020 [Member] | Equity Component Of Convertible Senior Note [Member]
Debt Instrument [Line Items]
Less: unamortized debt issuance costs		(5,000,000)	(5,000,000)
Equity component of convertible debt, deferred taxes		$ 50,000,000	$ 50,000,000
[1]	Recorded in additional paid-in capital, net of $5 million of issuance costs and $50 million of deferred taxes as of December 31, 2017 and 2016.

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations
Asset retirement obligations, current portion		$ 5,000	$ 8,000
Reconciliation of the Company's asset retirement obligations
Balance at the beginning of the period		177,004	161,908
Additional liability incurred		7,727	3,238
Revisions to estimated cash flows	[1],[2]	(52,947)	11,620
Accretion expense		13,809	13,800
Obligations on sold properties		(6,988)	(4,771)
Liabilities settled		(4,368)	(8,791)
Balance at the end of the period		$ 134,237	$ 177,004
[1]	Revisions to estimated cash flows during the year ended December 31, 2016 are primarily attributable to the acceleration in the estimated timing of abandonment of a large number of Whiting's producing properties resulting from decreases in commodity prices used in the calculation of the Company's reserves as of December 31, 2016, which shortened the economic lives of these properties. For the year ended December 31, 2016, the increase was partially offset by decreases in the estimates of future costs required to plug and abandon wells in certain fields in the Central and Northern Rocky Mountains.
[2]	Revisions to estimated cash flows during the year ended December 31, 2017 are primarily attributable to the deferral of the estimated timing of abandonment of a large number of Whiting's producing properties resulting from increases in commodity prices used in the calculation of the Company's reserves as of December 31, 2017, which lengthened the economic lives of these properties. In addition, during 2017 there were decreases in the estimates of future costs required to plug and abandon wells in certain fields in the Northern Rocky Mountains.

DERIVATIVE FINANCIAL INSTRUME55

DERIVATIVE FINANCIAL INSTRUMENTS (Narrative) (Details)		Feb. 01, 2018USD ($)	Jul. 19, 2017USD ($)	Jul. 31, 2016USD ($)$ / bbl	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Derivative Financial Instruments [Line Items]
Additional proceeds from disposal for specified period for each $0.01 average NYMEX futures is above threshold price per Bbl				$ 100,000
Average price per Bbl threshold for additional proceeds from sale | $ / bbl				50
Maximum possible additional proceeds from divestiture of business				$ 100,000,000
Amount received from settled contingent payment			$ 35,000,000
Level 3 [Member]
Derivative Financial Instruments [Line Items]
Fair value liabilities					$ (63,278,000)	$ (9,214,000)	$ (4,027,000)
Embedded derivatives [Member]
Derivative Financial Instruments [Line Items]
Derivative Asset					0
Recurring Basis [Member]
Derivative Financial Instruments [Line Items]
Derivative Asset						50,632,000
Recurring Basis [Member] | Embedded derivatives [Member] | Level 3 [Member]
Derivative Financial Instruments [Line Items]
Embedded Derivative, Fair Value of Embedded Derivative Liability					$ 0	0
Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
Derivative Asset	[1]					50,632,000
Not Designated as ASC 815 Hedges [Member] | Other Long Term Assets [Member] | Embedded derivatives [Member]
Derivative Financial Instruments [Line Items]
Derivative Asset	[1]					$ 50,632,000
Subsequent Event [Member] | Level 3 [Member]
Derivative Financial Instruments [Line Items]
Fair value liabilities		$ 0
Subsequent Event [Member] | Crude Oil Sales And Delivery Contract [Member]
Derivative Financial Instruments [Line Items]
Payment to settle future minimum volume commitments		$ 61,000,000
[1]	Because counterparties to the Company's financial derivative contracts subject to master netting arrangements 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 these tables.

DERIVATIVE FINANCIAL INSTRUME56

DERIVATIVE FINANCIAL INSTRUMENTS (Derivative instruments) (Details) - Whiting Petroleum Corporation [Member] - Crude Oil [Member]		Jan. 23, 2018bblitem	Dec. 31, 2017item$ / bbl
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl) | item			17,400,000
Three-way collars [Member] | Jan - Dec 2018 [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl) | item	[1]		17,400,000
Derivative, Floor Price (in dollars per Bbl) | $ / bbl	[1]		37.07
Derivative, Strike Price (in dollars per Bbl) | $ / bbl	[1]		47.07
Derivative, Cap Price (in dollars per Bbl) | $ / bbl	[1]		57.30
Collars [Member] | Jan 2019 - Jun 2019 [Member] | Subsequent Event [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl) | bbl		900,000
Swap [Member] | Jan - Dec 2018 [Member] | Subsequent Event [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl) | item		4,400,000
[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.

DERIVATIVE FINANCIAL INSTRUME57

DERIVATIVE FINANCIAL INSTRUMENTS (Schedule of effects of commodity derivative instruments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	$ 122,847	$ (587)	$ (217,972)
Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	122,847	(587)	(217,972)
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	104,138	58,771	$ (217,972)
Embedded derivatives [Member] | Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	$ 18,709	$ (59,358)

DERIVATIVE FINANCIAL INSTRUME58

DERIVATIVE FINANCIAL INSTRUMENTS (Location and fair value of derivative instruments, assets) (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Not Designated as ASC 815 Hedges [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	[1]	$ 9,829	$ 81,532
Gross Amounts Offset	[1]	(9,829)	(30,900)
Total financial assets	[1]		50,632
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | Prepaid Expenses and Other [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	[1]	9,829	21,405
Gross Amounts Offset	[1]	(9,829)	(21,405)
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | Other Long Term Assets [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	[1]		9,495
Gross Amounts Offset	[1]		(9,495)
Embedded derivatives [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Total financial assets		$ 0
Embedded derivatives [Member] | Not Designated as ASC 815 Hedges [Member] | Other Long Term Assets [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	[1]		50,632
Total financial assets	[1]		$ 50,632
[1]	Because counterparties to the Company's financial derivative contracts subject to master netting arrangements 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 these tables.

DERIVATIVE FINANCIAL INSTRUME59

DERIVATIVE FINANCIAL INSTRUMENTS (Location and fair value of derivative instruments, liabilities) (Details) - Not Designated as ASC 815 Hedges [Member] - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Gross amounts of derivative liabilities and gross amounts offset [Line Items]
Gross Amounts of Recognized Liabilities	[1]	$ 142,354	$ 58,757
Gross Amounts Offset	[1]	(9,829)	(30,900)
Total financial liabilities	[1]	132,525	27,857
Commodity contracts [Member] | Derivative Liabilities [Member]
Gross amounts of derivative liabilities and gross amounts offset [Line Items]
Gross Amounts of Recognized Liabilities	[1]	142,354	39,033
Gross Amounts Offset	[1]	(9,829)	(21,405)
Total financial liabilities	[1]	$ 132,525	17,628
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]		19,724
Gross Amounts Offset	[1]		(9,495)
Total financial liabilities	[1]		$ 10,229
[1]	Because counterparties to the Company's financial derivative contracts subject to master netting arrangements 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 these tables.

FAIR VALUE MEASUREMENTS (Narrat

FAIR VALUE MEASUREMENTS (Narrative) (Details) - USD ($) $ in Millions	Feb. 01, 2018	Jul. 19, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-recurring assets at fair value, Impairment Loss (Before Tax)			$ 835		$ 1,600
Amount received from settled contingent payment		$ 35
Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-recurring assets at fair value, Impairment Loss (Before Tax)				$ 0
Crude Oil Sales And Delivery Contract [Member] | Subsequent Event [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Payment to settle future minimum volume commitments	$ 61

FAIR VALUE MEASUREMENTS (Summar

FAIR VALUE MEASUREMENTS (Summary of the fair values and carrying value of debt instruments) (Details) - USD ($) $ in Thousands		Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Sep. 30, 2013	Sep. 26, 2013	Sep. 30, 2010
Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[1]	$ 3,843,689		$ 3,016,032
Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[2]	$ 3,723,429		$ 2,985,303
6.5% Senior Subordinated Notes due 2018 [Member] | Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Interest Rate (as a percent)		6.50%		6.50%					6.50%
6.5% Senior Subordinated Notes due 2018 [Member] | Senior Subordinated Notes [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[1]			$ 275,121
6.5% Senior Subordinated Notes due 2018 [Member] | Senior Subordinated Notes [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[2]			$ 273,506
5.0% Senior Notes due 2019 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Interest Rate (as a percent)		5.00%	[3]	5.00%			5.00%
5.0% Senior Notes due 2019 [Member] | Senior Notes [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[1]	$ 985,444		$ 961,409
5.0% Senior Notes due 2019 [Member] | Senior Notes [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[2]	$ 958,713		$ 956,607
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure						$ 1,000,000
Interest Rate (as a percent)		1.25%		1.25%	1.25%	1.25%
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[1]	$ 517,109		$ 503,057
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[2]	$ 506,231		$ 483,465
5.75% Senior Notes due 2021 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Interest Rate (as a percent)		5.75%		5.75%			5.75%	5.75%
5.75% Senior Notes due 2021 [Member] | Senior Notes [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[1]	$ 897,633		$ 868,149
5.75% Senior Notes due 2021 [Member] | Senior Notes [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[2]	$ 869,284		$ 868,460
6.25% Senior Notes due 2023 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Interest Rate (as a percent)		6.25%		6.25%	6.25%	6.25%
6.25% Senior Notes due 2023 [Member] | Senior Notes [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[1]	$ 418,503		$ 408,296
6.25% Senior Notes due 2023 [Member] | Senior Notes [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[2]	$ 403,940		$ 403,265
6.625% Senior Notes due 2026 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Interest Rate (as a percent)		6.625%
6.625% Senior Notes due 2026 [Member] | Senior Notes [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[1]	$ 1,025,000
6.625% Senior Notes due 2026 [Member] | Senior Notes [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	[2]	$ 985,261
[1]	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.
[2]	Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums.
[3]	On January 26, 2018, the Company used the proceeds from the December 2017 issuance of its 6.625% Senior Notes due January 2026 as well as borrowings under its credit agreement to redeem all of the outstanding 5.0% Senior Notes due March 2019.

FAIR VALUE MEASUREMENTS (Fair v

FAIR VALUE MEASUREMENTS (Fair value assets and liabilities measured on a recurring basis) (Details) - Recurring Basis [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Financial Assets
Total financial assets		$ 50,632
Financial Liabilities
Total financial liabilities	$ 132,525	27,857
Commodity contracts [Member]
Financial Liabilities
Financial liabilities - current	132,525	17,628
Financial liabilities - non-current		10,229
Embedded derivatives [Member]
Financial Assets
Financial assets - non-current		50,632
Level 2 [Member]
Financial Assets
Total financial assets		50,632
Financial Liabilities
Total financial liabilities	69,247	18,643
Level 2 [Member] | Commodity contracts [Member]
Financial Liabilities
Financial liabilities - current	69,247	14,664
Financial liabilities - non-current		3,979
Level 2 [Member] | Embedded derivatives [Member]
Financial Assets
Financial assets - non-current		50,632
Level 3 [Member]
Financial Liabilities
Total financial liabilities	63,278	9,214
Level 3 [Member] | Commodity contracts [Member]
Financial Liabilities
Financial liabilities - current	$ 63,278	2,964
Financial liabilities - non-current		$ 6,250

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, 2017	Dec. 31, 2016
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy
Fair value liability, beginning of period		$ (9,214)	$ (4,027)
Recognition of embedded derivatives associated with convertible note issuances			(89,884)
Fair value liability, end of period		(63,278)	(9,214)
Embedded derivatives [Member]
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy
Unrealized gains (losses) on derivative contracts included in earnings	[1]		47,965
Settlement of embedded derivatives upon conversion of convertible notes			41,919
Commodity contracts [Member]
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy
Unrealized gains (losses) on derivative contracts included in earnings	[1]	$ (54,064)	$ (5,187)
[1]	Included in 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) - Commodity contracts [Member] - Level 3 [Member]	12 Months Ended
	Dec. 31, 2017$ / bbl
Maximum [Member]
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Market Differential For Crude Oil, Amount (Per Bbl)	4.92
Minimum [Member]
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Market Differential For Crude Oil, Amount (Per Bbl)	4.08

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, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-recurring assets at fair value, Impairment Loss (Before Tax)		$ 835,000		$ 1,600,000
Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-recurring assets at fair value, Impairment Loss (Before Tax)			$ 0
Nonrecurring [Member] | Proved Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property	[1]	389,390
Total non-recurring assets					$ 1,200,000
Non-recurring assets at fair value, Impairment Loss (Before Tax)	[1]	834,950
Nonrecurring [Member] | Proved Properties [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property	[1]	$ 389,390
[1]	During the fourth quarter of 2017, proved oil and gas properties at the Redtail field in the Denver Julesburg Basin (the "DJ Basin") in Weld County, Colorado, with a previous carrying amount of $1.2 billion were written down to their fair value as of December 31, 2017 of $389 million, resulting in a non-cash impairment charge of $835 million which was recorded within exploration and impairment expense.

SHAREHOLDERS' EQUITY AND NONCON

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Narrative) (Details) $ / shares in Units, $ in Millions	Nov. 08, 2017	Apr. 01, 2015USD ($)shares	Nov. 30, 2017	Mar. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2017shares	Dec. 31, 2015shares	[1]	Dec. 31, 2016shares
Class of Stock [Line Items]
Ratio	0.25		0.25
Common stock, shares authorized					225,000,000			600,000,000
Common Stock [Member]
Class of Stock [Line Items]
Issuance of common stock (in shares)		500,000		8,750,000		9,250,000
Shares issued, per share | $ / shares				$ 120
Issuance of common stock, net | $		$ 61		$ 1,000
Over-Allotment Option [Member] | Common Stock [Member]
Class of Stock [Line Items]
Period of option to purchase additional shares, days					30 days
Number of additional shares available for purchase					1,312,500
[1]	All common share amounts have been retroactively adjusted for the 2015 and 2016 periods to reflect the Company's one-for-four reverse stock split in November 2017, as described in Note 8 to these consolidated financial statements.

SHAREHOLDERS_ EQUITY AND NONC67

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST (Schedule of noncontrolling interest) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Noncontrolling Interest disclosures [Line Items]
Balance at beginning of period	$ 7,962	$ 7,984
Net loss	(14)	(22)	$ (86)
Conveyance of ownership interest	(7,948)
Balance at end of period		$ 7,962	$ 7,984
Noncontrolling Interest [Member]
Noncontrolling Interest disclosures [Line Items]
Conveyance of ownership interest	$ (7,948)
Sustainable Water Resources, LLC [Member]
Noncontrolling Interest disclosures [Line Items]
Third party ownership interest (as a percent)		25.00%

STOCK-BASED COMPENSATION (Narra

STOCK-BASED COMPENSATION (Narrative) (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)item$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares
Share-based compensation disclosures [Line Items]
Stock compensation expense | $	$ 22	$ 26	$ 28
Granted (in dollars per share) | $ / shares	$ 44.89
Unrecognized compensation cost | $	$ 18
Weighted average period over which cost will be recognized	2 years
Total fair value of restricted stock vested | $	$ 15	$ 5	4
Stock Option [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	225,000
Maximum number of Shares per non-employee	25,000
Vesting (service) period	3 years
Exercise of stock options (in shares)
Unrecognized compensation cost | $	$ 0
Aggregate Intrinsic Value, options Exercised | $			$ 2
Stock Appreciation Rights (SARs) [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	225,000
Maximum number of Shares per non-employee	25,000
Restricted stock [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	150,000
Maximum number of Shares per non-employee	25,000
Restricted Stock Units [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	150,000
Maximum number of Shares per non-employee	25,000
Performance Shares [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	150,000
Performance Units [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	150,000
2013 Equity Plan [Member]
Share-based compensation disclosures [Line Items]
Number of shares authorized upon shareholder's approval	1,375,000
Number of shares available for grant	1,137,723
Service-Based Restricted Stock [Member] | Restricted stock [Member]
Share-based compensation disclosures [Line Items]
Granted (in shares)	538,194	737,912	205,971
Granted (in dollars per share) | $ / shares	$ 40.66	$ 27.82	$ 123.72
Service-Based Restricted Stock [Member] | Restricted Stock Units [Member]
Share-based compensation disclosures [Line Items]
Granted (in shares)	39,619
Executive officers and employees [Member] | Restricted stock [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	3 years
Executive officers and employees [Member] | Restricted Stock Units [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	3 years
Minimum [Member] | Directors [Member] | Restricted stock [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	1 year
Market-based vesting criteria [Member] | Executive officers [Member] | Restricted stock [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	3 years
Market-based vesting criteria [Member] | Executive officers [Member] | Performance Shares [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	3 years
Granted (in shares)	168,466	268,278	97,937
Granted (in dollars per share) | $ / shares	$ 63.04	$ 25.56	$ 133
Market-based vesting criteria [Member] | Minimum [Member] | Executive officers [Member] | Performance Shares [Member]
Share-based compensation disclosures [Line Items]
Possible multiplier of shares earned | item	0
Market-based vesting criteria [Member] | Maximum [Member] | Executive officers [Member] | Performance Shares [Member]
Share-based compensation disclosures [Line Items]
Possible multiplier of shares earned | item	2

STOCK-BASED COMPENSATION (Assum

STOCK-BASED COMPENSATION (Assumption for valuing market based restricted shares) (Details) - Market-based vesting criteria [Member] - Executive officers [Member] - Performance Shares [Member] - item	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of simulations	2,500,000	2,500,000	2,500,000
Expected volatility (as a percent)	82.44%	60.80%	40.30%
Risk-free interest rate (as a percent)	1.52%	1.13%	0.99%
Dividend yield (as a percent)	0.00%	0.00%	0.00%

STOCK-BASED COMPENSATION (Summa

STOCK-BASED COMPENSATION (Summary of nonvested restricted stock) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in dollars per share)	$ 54.19
Granted (in dollars per share)	44.89
Vested (in dollars per share)	51.23
Forfeited (in dollars per share)	81.97
Balance at the end of the period (in dollars per share)	$ 44.99	$ 54.19
Restricted stock [Member] | 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)	766,818
Granted (in shares)	538,194	737,912	205,971
Vested (in shares)	(339,199)
Forfeited (in shares)	(67,392)
Balance at the end of the period (in shares)	898,421	766,818
Granted (in dollars per share)	$ 40.66	$ 27.82	$ 123.72
Restricted Stock Units [Member] | Service-Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	39,619
Balance at the end of the period (in shares)	39,619
Performance Shares [Member] | 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)	523,172
Granted (in shares)	168,466
Forfeited (in shares)	(194,111)
Balance at the end of the period (in shares)	497,527	523,172

STOCK-BASED COMPENSATION (Sum71

STOCK-BASED COMPENSATION (Summary of stock options outstanding) (Details) - Stock Option [Member] - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in shares)	128,524
Exercised (in shares)
Forfeited or expired (in shares)	(6,490)
Balance at the end of the period (in shares)	122,034
Options vested (in shares)	122,034
Options exercisable (in shares)	122,034
Balance at the beginning of the period (in dollars per share)	$ 158.17
Forfeitures or expired (in dollars per share)	207.86
Balance at the end of the period (in dollars per share)	154.32
Options vested (in dollars per share)	154.32
Options exercisable (in dollars per share)	$ 154.32
Aggregate Intrinsic Value, options Exercised		$ 2,000,000
Aggregate Intrinsic Value, options outstanding, end of period	$ 28,000
Options vested, Aggregate Intrinsic Value	28,000
Options exercisable, Aggregate Intrinsic Value	$ 28,000
Weighted Average Remaining Contractual Term, options outstanding	2 years 4 months 24 days
Weighted Average Remaining Contractual Term, options vested	2 years 4 months 24 days
Weighted Average Remaining Contractual Term, options exercisable	2 years 4 months 24 days

INCOME TAXES (Narrative) (Detai

INCOME TAXES (Narrative) (Details) - USD ($) $ in Thousands	Jan. 01, 2018	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
U.S. statutory income tax rate (as a percent)			35.00%	35.00%	35.00%
Valuation allowance recognized		$ (41,000)		$ 259,000
EOR credit carryforwards			$ 7,946	7,946
Alternative minimum tax credit carryforwards				7,847
Tax credit, alternative minimum tax recognized			7,000
Valuation allowance			271,300	264,461
Tax Cut and Jobs Act of 2017, income tax expense, revaluation of deferred tax assets and liabilities			51,000
Tax Cut and Jobs Act of 2017, income tax benefit, reduction in existing valuation allowances			93,000
Tax Cut and Jobs Act of 2017, deferred tax, valuation allowance			$ 119,000
Tax Cut and Jobs Act of 2017, possible impact, deductibility of net interest expense in excess of percentage of adjusted taxable income Which			30.00%
Tax Cut and Jobs Act of 2017, possible impact, limitation on net operating loss, percentage of taxable income			80.00%
Uncertain tax positions			$ 0	0
Unrecognized tax benefit				170
Unrecognized tax benefits, penalties and interest expense			0	0	$ 0
Unrecognized tax benefits, penalties and interest accrued			0	0	$ 0
Subsequent Event [Member]
Operating Loss Carryforwards [Line Items]
U.S. statutory income tax rate (as a percent)	21.00%
IRC Section 382 Limitations [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance			138,000	251,000
EOR Credits [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance			8,000	8,000
Canadian NOL Carryforwards [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance			5,000	$ 5,000
Short-Term Capital Loss Carryforwards [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance			1,000
Federal [Member]
Operating Loss Carryforwards [Line Items]
Federal operating loss carryforwards			$ 2,900,000

INCOME TAXES (Schedule of incom

INCOME TAXES (Schedule of income expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
INCOME TAXES [Abstract]
Federal	$ (7,305)	$ (7,340)
State	14	150	$ (357)
Total current income tax benefit	(7,291)	(7,190)	(357)
Federal	(398,686)	(65,130)	(736,520)
State	(77,002)	(15,326)	(37,350)
Total deferred income tax benefit	(475,688)	(80,456)	(773,870)
Total income tax benefit	$ (482,979)	$ (87,646)	$ (774,227)

INCOME TAXES (Reconciliation of

INCOME TAXES (Reconciliation of statutory income tax expense to income expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes [Line Items]
U.S. statutory income tax rate (as a percent)	35.00%	35.00%	35.00%
U.S. statutory income tax benefit	$ (602,219)	$ (499,370)	$ (1,047,723)
State income taxes, net of federal benefit	(39,557)	(33,050)	(44,654)
Valuation allowance	120,880
Impairment charge after enactment of federal tax reform	114,293
IRC Section 382 limitation	(45,899)	259,494
Non-deductible convertible debt expenses		174,071
Goodwill impairment			305,820
Market-based equity awards	7,003	8,352	2,690
Other	4,553	(2,163)	2,290
Total income tax benefit	(482,979)	(87,646)	(774,227)
Federal Tax Reform [Member]
Income Taxes [Line Items]
Enacted changes in tax laws	$ (42,033)
State Tax Laws [Member]
Income Taxes [Line Items]
Enacted changes in tax laws		$ 5,020	$ 7,350

INCOME TAXES (Components of def

INCOME TAXES (Components of deferred income tax assets and liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
INCOME TAXES [Abstract]
Net operating loss carryforward	$ 828,617	$ 1,248,034
Derivative instruments	31,567	6,145
Asset retirement obligations	16,138	21,398
Restricted stock compensation	9,704	12,171
EOR credit carryforwards	7,946	7,946
Alternative minimum tax credit carryforwards		7,847
Other	11,549	19,356
Total deferred income tax assets	905,521	1,322,897
Less valuation allowances	(271,300)	(264,461)
Net deferred income tax assets	634,221	1,058,436
Oil and gas properties	566,747	1,412,781
Trust distributions	54,980	94,120
Discount on convertible senior notes	12,494	27,224
Total deferred income tax liabilities	$ 634,221	1,534,125
Total net deferred income tax liabilities		$ 475,689

EARNINGS PER SHARE (Narrative)

EARNINGS PER SHARE (Narrative) (Details) item in Millions	12 Months Ended
	Dec. 31, 2017itemshares	Dec. 31, 2016shares	Dec. 31, 2015shares
Convertible Debt Securities [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Antidilutive securities excluded from computation of earnings per share		10,820,758
Stock options [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Antidilutive securities excluded from computation of earnings per share	1,083	1,158	21,391
Stock options excluded from earnings per share calculation (in shares)	554,580	479,452	128,689
Issuable Upon Conversion [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Debt instrument, convertible, number of common stock | item	3.6
Service-Based Restricted Stock [Member] | Restricted stock [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Antidilutive securities excluded from computation of earnings per share	509,744	444,646	129,034
Market-Based Restricted Stock [Member] | Restricted stock [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Antidilutive securities excluded from computation of earnings per share			169,069
Restricted stock excluded from earnings per share calculation (in shares)	5,447	92,548

EARNINGS PER SHARE (Reconciliat

EARNINGS PER SHARE (Reconciliations between basic and diluted earnings per share)(Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Basic Loss Per Share
Net loss attributable to common shareholders, basic		$ (1,237,648)	$ (1,339,102)	$ (2,219,182)
Weighted average shares outstanding, basic	[1]	90,683	62,967	48,868
Loss per common share, basic (in dollars per share)	[1]	$ (13.65)	$ (21.27)	$ (45.41)
Diluted Loss Per Share
Adjusted net loss attributable to common shareholders, diluted		$ (1,237,648)	$ (1,339,102)	$ (2,219,182)
Weighted average shares outstanding, diluted	[1]	90,683	62,967	48,868
Loss per common share, diluted (in dollars per share)	[1]	$ (13.65)	$ (21.27)	$ (45.41)
[1]	All share and per share amounts have been retroactively adjusted for the 2015 and 2016 periods to reflect the Company's one-for-four reverse stock split in November 2017, as described in Note 8 to these consolidated financial statements.

COMMITMENTS AND CONTINGENCIES78

COMMITMENTS AND CONTINGENCIES (Narrative) (Details) $ in Thousands	Feb. 01, 2018USD ($)contract	Dec. 31, 2017USD ($)ft²contractitemMBbls	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Rental expense		$ 8,000	$ 9,000	$ 9,000
Crude Oil [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Delivery commitments for 2018 | MBbls		14,800
Delivery commitments for year 2019 | MBbls		16,000
Delivery commitments for year 2020 | MBbls		4,100
Actual Impact On Earnings And Financing Needs Resulting From Inability To Meet Oil And Gas Delivery Commitments, Payment Amount		$ 66,000	43,000	15,000
Take-Or-Pay Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of take or pay purchase agreements | contract		1
Payments under purchase contracts		$ 22,000	1,000
Future commitments under purchase agreements		$ 23,000
Pipeline Transportation Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of pipeline transportation agreements | contract		3
Number of pipeline transportation agreements with fixed monthly reservation fees on dedicated pipelines, variable charge on actual transporation volumes | contract		2
Number of suppliers | item		2
Payments under purchase contracts		$ 7,000	5,000	3,000
Estimated minimum future commitments under transportation agreement		17,000
Future commitments under purchase agreements		38,326
Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Payments under purchase contracts		$ 29,000	31,000	18,000
Number of contracts with drilling rig companies | contract		3
Termination penalties		$ 11,000
Future commitments under purchase agreements		$ 19,742
Water Disposal Agreement [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of water disposal agreements | item		1
Transportation and disposal cost incurred		$ 16,000	8,000	$ 0
Transportation and disposal, deficiency payments		4,000	$ 2,000
Future commitments under purchase agreements		$ 122,000
Expiration 2018 [Member] | Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts with drilling rig companies | contract		2
Expiration 2019 [Member] | Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts with drilling rig companies | contract		1
Denver, Colorado office [Member] | Expiration 2019 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²		222,900
Dickinson, North Dakota office [Member] | Expiration 2020 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²		36,500
Midland, Texas office [Member] | Expiration 2020 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²		44,500
Mountrail County, North Dakota [Member] | Crude Oil [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Delivery commitments, volume per day | MBbls		15,000
Delivery commitment term		7 years
Number Of Delivery Commitments | item		1
Weld County, Colorado [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number Of Delivery Commitments | contract		2
Weld County, Colorado [Member] | Subsequent Event [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number Of Delivery Commitments | contract	1
Crude Oil Sales And Delivery Contract [Member] | Subsequent Event [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Payments for Derivative Instrument, Investing Activities	$ 61,000

COMMITMENTS AND CONTINGENCIES79

COMMITMENTS AND CONTINGENCIES (Minimum future payments under non-cancelable operating leases and unconditional purchase obligations) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
2,018	$ 32,313
2,019	12,068
2,020	6,171
2,021	5,369
2,022	5,369
Thereafter	11,481
Total	72,771
Non-Cancelable Leases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,018	7,502
2,019	6,399
2,020	802
Total	14,703
Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,018	19,442
2,019	300
Total	19,742
Pipeline Transportation Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,018	5,369
2,019	5,369
2,020	5,369
2,021	5,369
2,022	5,369
Thereafter	11,481
Total	$ 38,326

CAPITALIZED EXPLORATORY WELL 80

CAPITALIZED EXPLORATORY WELL COSTS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2015
CAPITALIZED EXPLORATORY WELL COSTS [Abstract]
Balance at the beginning of the period		$ 14,293
Additions to capitalized exploratory well costs pending the determination of proved reserves	13,894	54,707
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(63,352)
Capitalized exploratory well costs charged to expense		$ (5,648)
Balance at the end of the period	13,894
Capitalized exploratory cost for exploratory wells in progress	$ 0

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - USD ($) $ in Millions	Feb. 01, 2018	Jan. 26, 2018
5.0% Senior Notes due 2019 [Member] | Senior Notes [Member]
Subsequent Event [Line Items]
Notes repurchased, principal amount		$ 961
Subsequent Event [Member] | 5.0% Senior Notes due 2019 [Member] | Senior Notes [Member]
Subsequent Event [Line Items]
Repurchase of notes		$ 1,000
Percentage of redemption price		102.976%
Crude Oil Sales And Delivery Contract [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Payment to settle future minimum volume commitments	$ 61