Chord Energy (WLLBW) 10-K 28 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 20, 2019	Jun. 30, 2018
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, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		91,268,384
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity Public Float			$ 4,798,000,000
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 13,607	$ 879,379
Accounts receivable trade, net	294,468	284,214
Derivative assets	68,342
Prepaid expenses and other	22,009	26,035
Total current assets	398,426	1,189,628
Property and equipment:
Oil and gas properties, successful efforts method	12,195,659	11,293,650
Other property and equipment	134,212	134,524
Total property and equipment	12,329,871	11,428,174
Less accumulated depreciation, depletion and amortization	(5,003,509)	(4,244,735)
Total property and equipment, net	7,326,362	7,183,439
Other long-term assets	34,785	29,967
TOTAL ASSETS	7,759,573	8,403,034
Current liabilities:
Current portion of long-term debt		958,713
Accounts payable trade	42,520	32,761
Revenues and royalties payable	228,284	171,028
Accrued capital expenditures	73,178	69,744
Accrued interest	55,080	40,971
Accrued lease operating expenses	37,499	36,865
Accrued liabilities and other	33,872	51,590
Taxes payable	31,357	28,771
Derivative liabilities		132,525
Accrued employee compensation and benefits	35,141	30,360
Total current liabilities	536,931	1,553,328
Long-term debt	2,792,321	2,764,716
Deferred income taxes	1,373
Asset retirement obligations	131,544	129,206
Other long-term liabilities	27,088	36,642
Total liabilities	3,489,257	4,483,892
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 225,000,000 shares authorized; 92,067,216 issued and 91,018,692 outstanding as of December 31, 2018 and 92,094,837 issued and 90,698,889 outstanding as of December 31, 2017	92	92
Additional paid-in capital	6,414,170	6,405,490
Accumulated deficit	(2,143,946)	(2,486,440)
Total equity	4,270,316	3,919,142
TOTAL LIABILITIES AND EQUITY	$ 7,759,573	$ 8,403,034

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
CONSOLIDATED BALANCE SHEETS [Abstract]
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	225,000,000	225,000,000
Common stock, shares issued	92,067,216	92,094,837
Common stock, shares outstanding	91,018,692	90,698,889

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
OPERATING REVENUES
Oil, NGL and natural gas sales		$ 2,081,414	$ 1,481,435	$ 1,284,982
OPERATING EXPENSES
Lease operating expenses		311,895	278,919	313,168
Gathering, transportation, compression and other		48,105	90,574	78,845
Production and ad valorem taxes		171,823	120,870	111,837
Depreciation, depletion and amortization		781,329	948,939	1,171,582
Exploration and impairment		67,368	936,177	121,468
General and administrative		123,250	124,288	146,878
Derivative (gain) loss, net		17,170	122,847	(587)
Loss on sale of properties		1,949	401,113	184,567
Amortization of deferred gain on sale		(11,354)	(12,963)	(14,570)
Total operating expenses		1,511,535	3,010,764	2,113,188
INCOME (LOSS) FROM OPERATIONS		569,879	(1,529,329)	(828,206)
OTHER INCOME (EXPENSE)
Interest expense		(197,474)	(191,088)	(557,620)
Loss on extinguishment of debt		(31,968)	(1,540)	(42,236)
Interest income and other		3,430	1,316	1,292
Total other expense		(226,012)	(191,312)	(598,564)
INCOME (LOSS) BEFORE INCOME TAXES		343,867	(1,720,641)	(1,426,770)
INCOME TAX EXPENSE (BENEFIT)
Current			(7,291)	(7,190)
Deferred		1,373	(475,688)	(80,456)
Total income tax expense (benefit)		1,373	(482,979)	(87,646)
NET INCOME (LOSS)		342,494	(1,237,662)	(1,339,124)
Net loss attributable to noncontrolling interests			14	22
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS		$ 342,494	$ (1,237,648)	$ (1,339,102)
INCOME (LOSS) PER COMMON SHARE
Basic (in dollars per share)	[1]	$ 3.77	$ (13.65)	$ (21.27)
Diluted (in dollars per share)	[1]	$ 3.73	$ (13.65)	$ (21.27)
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic (in shares)	[1]	90,953	90,683	62,967
Diluted (in shares)	[1]	91,869	90,683	62,967
[1]	All share and per share amounts have been retroactively adjusted for the 2016 period 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 OP_2

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, 2018	Dec. 31, 2017	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 342,494	$ (1,237,662)	$ (1,339,124)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	781,329	948,939	1,171,582
Deferred income tax expense (benefit)	1,373	(475,688)	(80,456)
Amortization of debt issuance costs, debt discount and debt premium	30,700	31,715	335,569
Stock-based compensation	12,669	21,641	25,647
Amortization of deferred gain on sale	(11,354)	(12,963)	(14,570)
Loss on sale of properties	1,949	401,113	184,567
Oil and gas property impairments	45,288	899,853	75,622
Exploratory dry hole costs			134
Loss on extinguishment of debt	31,968	1,540	42,236
Non-cash derivative (gain) loss	(139,831)	131,129	151,151
Payment for settlement of commodity derivative contract	(61,036)
Other, net	(6,706)	(9,255)	(10,185)
Changes in current assets and liabilities:
Accounts receivable trade, net	(11,571)	(110,879)	155,416
Prepaid expenses and other	4,026	(444)	586
Accounts payable trade and accrued liabilities	11,368	(24,953)	(62,774)
Revenues and royalties payable	56,751	23,799	(32,185)
Taxes payable	2,586	(10,776)	(8,206)
Net cash provided by operating activities	1,092,003	577,109	595,010
CASH FLOWS FROM INVESTING ACTIVITIES
Drilling and development capital expenditures	(813,981)	(830,552)	(539,208)
Acquisition of oil and gas properties	(142,723)	(21,429)	(4,718)
Other property and equipment	(1,096)	(4,596)	(9,255)
Proceeds from sale of oil and gas properties	4,746	929,974	313,355
Deposit received on properties held for sale			17,250
Net cash provided by (used in) investing activities	(953,054)	73,397	(222,576)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit agreement	2,214,265	1,900,000	1,310,000
Repayments of borrowings under credit agreement	(2,214,265)	(2,450,000)	(1,560,000)
Issuance of 6.625% Senior Notes due 2026		1,000,000
Redemption of 6.5% Senior Subordinated Notes due 2018		(275,121)
Redemption of 5.0% Senior Notes due 2019	(990,023)
Early conversion payments for New Convertible Notes			(41,919)
Debt issuance costs	(10,709)	(13,150)	(22,499)
Restricted stock used for tax withholdings	(4,744)	(6,081)	(844)
Issuance of Senior Notes		1,000,000
Proceeds from stock options exercised	755
Net cash provided by (used in) financing activities	(1,004,721)	155,648	(315,262)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	(865,772)	806,154	57,172
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Beginning of period	879,379	73,225	16,053
End of period	13,607	879,379	73,225
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Income taxes paid (refunded), net	(32)	49	(1,044)
Interest paid, net of amounts capitalized	152,665	163,151	239,963
NONCASH INVESTING ACTIVITIES
Accrued capital expenditures and accounts payable related to property additions	$ 90,358	$ 80,762	$ 65,052

CONSOLIDATED STATEMENTS OF CA_2

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2013	Sep. 30, 2010
6.625% Senior Notes due 2026 [Member]
Interest Rate (as a percent)	6.625%	6.625%
6.5% Senior Subordinated Notes due 2018 [Member]
Interest Rate (as a percent)	6.50%	6.50%		6.50%
5.0% Senior Notes due 2019 [Member]
Interest Rate (as a percent)	5.00%		5.00%

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Thousands, $ in Thousands		Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Deficit [Member]	Total Whiting Shareholders' Equity [Member]	Noncontrolling Interest [Member]	Total
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 income (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 income (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
Cumulative effect of change in accounting principle			220	(220)
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
Net income (loss)				342,494	342,494		342,494
Exercise of stock options			755		755		755
Exercise of stock options (in shares)	[1]	16
Restricted stock issued (in shares)	[1]	451
Restricted stock forfeited (in shares)	[1]	(351)
Restricted stock used for tax withholdings			(4,744)		(4,744)		(4,744)
Restricted stock used for tax withholdings (in shares)	[1]	(144)
Stock-based compensation			12,669		12,669		12,669
BALANCES at Dec. 31, 2018		$ 92	$ 6,414,170	$ (2,143,946)	$ 4,270,316		$ 4,270,316
BALANCES (in shares) at Dec. 31, 2018	[1]	92,067
[1]	All common share amounts have been retroactively adjusted for the 2016 period 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 EQ_2

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, 2018
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	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, 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 and its consolidated subsidiaries. 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 statements of operations have been reclassified to conform to the current year presentation. These include the reclassification of gathering, transportation, compression and other expenses and ad valorem taxes from previously reported lease operating expenses in the consolidated statements of operations. For all periods presented, gathering, transportation, compression and other expenses are presented as a separate caption and ad valorem taxes are combined with production taxes. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported. Cash and Cash Equivalents —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 related to a deposit received in connection with the sale of Whiting’s interests in the Robinson Lake and Belfield gas processing plants in North Dakota. 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 “Acquisitions and Divestitures” footnote for further information on this transaction. 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, 2018 and 2017, the Company had an allowance for doubtful accounts of $12 million and $17 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 $23 million and $24 million as of December 31, 2018 and 2017, 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 $5 million and $7 million as of December 31, 2018 and 2017, 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 undiscounted 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 $835 million for the year ended December 31, 2017, 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. 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 $37 million, $59 million and $73 million for the years ended December 31, 2018, 2017 and 2016, 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. Costs 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. 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 —Revenues are predominantly derived from the sale of produced oil, NGLs and natural gas. In May 2014, the FASB issued Accounting Standards Update No. 2014‑09, Revenue from Contracts with Customers (“ASU 2014‑09”). The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB ASC Topic 606 – Revenue from Contracts with Customers (“ASC 606”). The objective of ASC 606 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASC 606 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard permits 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 adopted ASC 606 effective January 1, 2018 using the modified retrospective approach. The adoption did not have an impact on the Company’s net income or cash flows, and the Company did not record a cumulative-effect adjustment to retained earnings as a result. However, the adoption did result in changes to the classification of certain fees incurred under pipeline gathering and transportation agreements and gas processing agreements, as well as certain costs attributable to non-operated properties, which led to an overall decrease in total revenues with a corresponding decrease in gathering, transportation, compression and other expenses under the new standard. Refer to the “Revenue Recognition” footnote for further information on the Company’s implementation of this standard. In accordance with ASC 606, oil and gas revenues are recognized when the performance obligation to deliver the product is met and control is transferred to the customer. Payments for product sales are received one to three months after delivery. At the end of each month when the performance obligation is satisfied and the amount of production delivered and the price received can be reasonably estimated, amounts due from customers are accrued in accounts receivable trade, net in the consolidated balance sheets. Variances between estimated revenue and actual payments are recorded in the month the payment is received. However, differences have been and are insignificant. 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, performance shares, performance share units and stock options, to employees and non-employee directors. The Company determines compensation expense for share-settled awards 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 awards granted under these plans based on the fair value of such awards at the end of each reporting period. Cash-settled awards are recorded as a liability in the consolidated balance sheets, and gains and losses from changes in fair value 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 2018, 2017 and 2016 were $7 million, $8 million and $8 million, respectively. Employees vest in employer contributions at 20% per year of completed service up to five years. 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 and performance 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, 2018, 2017 and 2016. Year Ended December 31, 2018 United Energy Trading, LLC 17 % Tesoro Crude Oil Co 14 % Philips 66 Company 11 % 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 eleven counterparties, all of which are participants in Whiting’s credit facility and all of which have investment-grade ratings from Moody’s and Standard & Poor’s. As of December 31, 2018, outstanding derivative contracts with JP Morgan Chase Bank, N.A., Wells Fargo Bank, N.A. and Capital One, N.A. represented 18%, 15% and 15%, respectively, of total crude oil volumes hedged. Recently Issued Accounting Pronouncements — 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. The FASB subsequently issued various ASUs which provided additional implementation guidance. ASU 2016‑02 and its amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The standard permits retrospective application through recognition of a cumulative-effect adjustment at the beginning of either the earliest reporting period presented or the period of adoption. The Company adopted ASU 2016-02 effective January 1, 2019 using a cumulative-effect adjustment as of the adoption date. Whiting elected certain practical expedients available under the standard including those that permit the Company to not (i) reassess prior conclusions reached under FASB ASC Topic 840 – Leases for lease identification, lease classification and initial direct costs, (ii) evaluate existing or expired land easements under the new standard and (iii) separate lease and non-lease components contained within a single agreement. Additionally, the Company has elected the short-term lease recognition exemption and therefore, leases with a term of one year or less will not be recognized on the consolidated balance sheet. Whiting is substantially complete with the assessment of its existing accounting policies and documentation, implementation of lease accounting software and enhancement of its internal controls. Adoption of the standard will result in the recognition of additional lease assets and liabilities on Whiting’s consolidated balance sheet as well as additional disclosures. The adoption is not expected to have a material impact to the Company’s consolidated statement of operations. As of December 31, 2018, the Company had approximately $254 million of contractual obligations related to its water disposal agreements, purchase obligations, pipeline transportation agreements, drilling rig contracts, real estate leases and automobile and equipment leases, and certain of these contracts will be recorded on its consolidated balance sheet under this standard.

OIL AND GAS PROPERTIES

OIL AND GAS PROPERTIES	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 are as follows (in thousands): December 31, 2018 2017 Proved leasehold costs $ 2,729,593 $ 2,622,576 Unproved leasehold costs 122,687 137,694 Costs of completed wells and facilities 9,182,384 8,288,591 Wells and facilities in progress 160,995 244,789 Total oil and gas properties, successful efforts method 12,195,659 11,293,650 Accumulated depletion (4,937,579) (4,185,301) Oil and gas properties, net $ 7,258,080 $ 7,108,349

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2018
ACQUISITIONS AND DIVESTITURES [Abstract]
ACQUISITIONS AND DIVESTITURES	3. ACQUISITIONS AND DIVESTITURES 2018 Acquisitions and Divestitures On July 31, 2018, the Company completed the acquisition of certain oil and gas properties located in Richland County, Montana and McKenzie County, North Dakota for an aggregate purchase price of $130 million (before closing adjustments). The properties consist of approximately 54,800 net acres in the Williston Basin, including interests in 117 producing oil and gas wells and undeveloped acreage. The revenue and earnings from these properties since the acquisition date are included in the Company’s consolidated financial statements for the year ended December 31, 2018 and are not material. Pro forma revenue and earnings for the acquired properties are not material to the Company’s consolidated financial statements and have not been presented accordingly. The acquisition was recorded using the acquisition method of accounting. The following table summarizes the preliminary allocation of the $127 million adjusted purchase price (which is still subject to post-closing adjustments) to the tangible assets acquired and liabilities assumed in this acquisition based on their relative fair values at the acquisition date, which did not result in the recognition of goodwill or a bargain purchase gain. As the purchase price is further adjusted for post-close adjustments and as oil and gas property valuations are completed, the final purchase price allocation may result in a different allocation to the tangible assets from that which is presented in the table below (in thousands): Cash consideration $ 126,938 Fair value of assets and liabilities acquired: Proved oil and gas properties $ 107,701 Unproved oil and gas properties 21,769 Total fair value of oil and gas properties acquired 129,470 Asset retirement obligations 2,532 Total fair value of net assets acquired $ 126,938 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. 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” footnote for more information on this embedded derivative instrument.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 (in thousands): December 31, 2018 2017 5.0% Senior Notes due 2019 $ - $ 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 1,000,000 Total principal 2,843,980 3,805,389 Unamortized debt discounts and premiums (28,994) (50,945) Unamortized debt issuance costs on notes (22,665) (31,015) Total debt 2,792,321 3,723,429 Less current portion of long-term debt - (958,713) Total long-term debt $ 2,792,321 $ 2,764,716 The following table shows five succeeding fiscal years of anticipated maturities for the Company’s long-term debt as of December 31, 2018 (in thousands): 2019 2020 2021 2022 2023 Long-term debt $ - $ 562,075 $ 873,609 $ - $ 408,296 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, 2018 had a borrowing base of $2.4 billion and aggregate commitments of $1.75 billion. As of December 31, 2018, the Company had $1.75 billion of available borrowing capacity under the credit agreement, 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. 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, 2018, $48 million was available for additional letters of credit under the agreement. The credit agreement provides for interest only payments until maturity, when the credit agreement expires and all outstanding borrowings are due. The credit agreement matures on April 12, 2023, provided that if at any time and for so long as any senior notes (other than the 2020 Convertible Senior Notes) have a maturity date prior to 91 days after April 12, 2023, the maturity date shall be the date that is 91 days prior to the maturity of such senior notes. Interest under the credit agreement 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 incurs commitment fees as set forth in the table below on the unused portion of the aggregate commitments of the lenders under the credit agreement, which are included as a component of interest expense. Applicable Applicable Margin for Base Margin for Commitment Ratio of Outstanding Borrowings to Borrowing Base Rate Loans Eurodollar Loans Fee Less than 0.25 to 1.0 0.50% 1.50% 0.375% Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 0.75% 1.75% 0.375% Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 1.00% 2.00% 0.50% Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 1.25% 2.25% 0.50% Greater than or equal to 0.90 to 1.0 1.50% 2.50% 0.50% The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders. Except for limited exceptions, the credit agreement also restricts the Company’s ability to make any dividend payments or distributions on its common stock. These restrictions apply to all of the Company’s restricted subsidiaries (as defined in the credit agreement). As of December 31, 2018, 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 and (ii) a total debt to last four quarters’ EBITDAX ratio of not greater than 4.0 to 1.0. The Company was in compliance with its covenants under the credit agreement as of December 31, 2018. 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, 2018: 2020 Convertible 2021 2023 2026 Senior Notes Senior Notes Senior Notes Senior Notes Outstanding principal (in thousands) $ 562,075 $ 873,609 $ 408,296 $ 1,000,000 Interest rate 1.25% 5.75% 6.25% 6.625% Maturity date Apr 1, 2020 Mar 15, 2021 Apr 1, 2023 Jan 15, 2026 Interest payment dates Apr 1, Oct 1 Mar 15, Sep 15 Apr 1, Oct 1 Jan 15, Jul 15 Make-whole redemption date (1) N/A (2) Dec 15, 2020 Jan 1, 2023 Oct 15, 2025 (1) 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. (2) 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”). 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 then outstanding 2019 Senior Notes. Refer to “Redemption of the 2019 Senior Notes” below for more information on the redemption of the 2019 Senior Notes. Exchange of Senior Notes and Senior Subordinated Notes for Convertible Notes . In March 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 in 2016, 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” footnote 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. In July 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. Redemption of 2018 Senior Subordinated Notes. In February 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. Redemption of 2019 Senior Notes. On January 26, 2018, the Company paid $1.0 billion to redeem all of the remaining $961 million aggregate principal amount of the 2019 Senior Notes, which payment consisted 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. As a result of the redemption, the Company recognized a $31 million loss on extinguishment of debt, which included the redemption premium and a non-cash charge for the acceleration of unamortized debt issuance costs on the notes. As of March 31, 2018, no 2019 Senior 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, 2018, the Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the 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, 2018, 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 consisted of the following at December 31, 2018 and 2017 (in thousands): December 31, 2018 2017 Liability component Principal $ 562,075 $ 562,075 Less: unamortized note discount (29,504) (51,666) Less: unamortized debt issuance costs (2,340) (4,178) Net carrying value $ 530,231 $ 506,231 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, 2018 and 2017. Interest expense recognized on the 2020 Convertible Senior Notes related to the stated interest rate and amortization of the debt discount totaled $29 million, $28 million and $43 million for the years ended December 31, 2018, 2017 and 2016, 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 2021 Senior Notes, 2023 Senior Notes, 2026 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 2021 Senior Notes, 2023 Senior Notes, 2026 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, 2018
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, 2018 and 2017 were $4 million and $5 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, 2018 and 2017 (in thousands): December 31, 2018 2017 Asset retirement obligation at January 1 $ 134,237 $ 177,004 Additional liability incurred 11,981 7,727 Revisions to estimated cash flows (1) (17,197) (52,947) Accretion expense 11,405 13,809 Obligations on sold properties (676) (6,988) Liabilities settled (3,916) (4,368) Asset retirement obligation at December 31 $ 135,834 $ 134,237 (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 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 INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2018
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 ensuring adequate funding 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, 2018. Derivative Contracted Crude Weighted Average NYMEX Price Instrument Period Oil Volumes (Bbl) for Crude Oil (per Bbl) Collars (1) Jan - Dec 2019 9,900,000 $51.21 - $77.14 Total 9,900,000 (1) Subsequent to December 31, 2018, the Company entered into swap contracts for 900,000 Bbl of crude oil volumes and additional costless collars for 900,000 Bbl of crude oil volumes for the second half of 2019. Crude Oil Sales and Delivery Contract. As of December 31, 2017, the Company had 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 had 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 requirements 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, 2017, the estimated fair value of this derivative contract was a liability of $63 million. 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 — In 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, 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 in the consolidated financial statements. 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, 2018 and 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 summarizes the effects of derivative instruments on the consolidated statements of operations for the years ended December 31, 2018, 2017 and 2016 (in thousands): (Gain) Loss Recognized in Income Not Designated as Statement of Operations Year Ended December 31, ASC 815 Hedges Classification 2018 2017 2016 Commodity contracts Derivative (gain) loss, net $ 17,170 $ 104,138 $ 58,771 Embedded derivatives Derivative (gain) loss, net - 18,709 (59,358) Total $ 17,170 $ 122,847 $ (587) 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, 2018 (1) Net Gross Recognized Recognized Gross Fair Value Not Designated as Assets/ Amounts Assets/ ASC 815 Hedges Balance Sheet Classification Liabilities Offset Liabilities Derivative assets Commodity contracts - current Derivative assets $ 69,735 $ (1,393) $ 68,342 Total derivative assets $ 69,735 $ (1,393) $ 68,342 Derivative liabilities Commodity contracts - current Derivative liabilities $ 1,393 $ (1,393) $ - Total derivative liabilities $ 1,393 $ (1,393) $ - 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 Derivative assets $ 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 (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, 2018
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. Cash, cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Company’s senior notes are recorded at cost and the 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, 2018 and 2017 (in thousands): December 31, 2018 December 31, 2017 Fair Carrying Fair Carrying Value (1) Value (2) Value (1) Value (2) 5.0% Senior Notes due 2019 $ - $ - $ 985,444 $ 958,713 1.25% Convertible Senior Notes due 2020 531,161 530,231 517,109 506,231 5.75% Senior Notes due 2021 829,929 870,545 897,633 869,284 6.25% Senior Notes due 2023 375,632 404,659 418,503 403,940 6.625% Senior Notes due 2026 865,000 986,886 1,025,000 985,261 Total $ 2,601,722 $ 2,792,321 $ 3,843,689 $ 3,723,429 (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 risk 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, 2018 and 2017, 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, 2018 Financial Assets Commodity derivatives – current $ - $ 68,342 $ - $ 68,342 Total financial assets $ - $ 68,342 $ - $ 68,342 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 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. The option model considers 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 had 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 therefore reflected this contract at fair value in its consolidated financial statements prior to settlement. This commodity derivative was valued based on a probability-weighted income approach which considered 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. Level 3 Fair Value Measurements — The 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, 2018 and 2017 (in thousands): Year Ended December 31, 2018 2017 Fair value liability, beginning of period $ (63,278) $ (9,214) Unrealized gains (losses) on commodity derivative contracts included in earnings (1) 2,242 (54,064) Settlement of commodity derivative contracts 61,036 - Transfers into (out of) Level 3 - - Fair value liability, end of period $ - $ (63,278) (1) Included in derivative (gain) loss, net in the consolidated statements of operations. 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, 2018. 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 million 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 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, 2018
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 New York Stock Exchange trading day. 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. Noncontrolling Interest —The Company’s noncontrolling interest represented 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 Balance at beginning of period $ 7,962 Net loss (14) Conveyance of ownership interest (7,948) Balance at end of period $ -

REVENUE RECOGNITION

REVENUE RECOGNITION	12 Months Ended
	Dec. 31, 2018
REVENUE RECOGNITION [Abstract]
REVENUE RECOGNITION	9. REVENUE RECOGNITION The Company adopted ASC 606 effective January 1, 2018, which replaces previous revenue recognition requirements under FASB ASC Topic 605 – Revenue Recognition (“ASC 605”). The standard was adopted using the modified retrospective approach which requires the Company to recognize in retained earnings at the date of adoption the cumulative effect of the application of ASC 606 to all existing revenue contracts which were not substantially complete as of January 1, 2018. The Company has elected the contract modification practical expedient which allows the Company to reflect the aggregate effect of all modifications prior to the date of adoption when applying ASC 606. Although the adoption of ASC 606 did not have an impact on the Company’s net income or cash flows, it did result in the reclassification of certain fees incurred under pipeline gathering and transportation agreements and gas processing agreements, as well as certain costs attributable to non-operated properties. Such reclassification led to an overall decrease in total revenues with a corresponding decrease in gathering, transportation, compression and other expenses (“GTC”) as follows (in thousands): Year Ended December 31, 2018 Under Under ASC 606 ASC 605 Difference OPERATING REVENUES Oil sales $ 1,850,052 $ 1,834,727 $ 15,325 NGL and natural gas sales 231,362 288,174 (56,812) Oil, NGL and natural gas sales $ 2,081,414 $ 2,122,901 $ (41,487) OPERATING EXPENSES Gathering, transportation, compression and other $ 48,105 $ 89,592 $ (41,487) Total operating expenses $ 1,511,535 $ 1,553,022 $ (41,487) INCOME FROM OPERATIONS $ 569,879 $ 569,879 $ - The reclassification of fees between operating revenues and expenses is the result of the Company’s assessment of the point in time at which its performance obligations under its commodity sales contracts are satisfied and control of the commodity is transferred to the customer. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as GTC, and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered. Whiting receives payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable trade, net in the consolidated balance sheets. As of January 1 and December 31, 2018, such receivable balances were $186 million and $165 million, respectively. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained. The Company has elected to utilize the practical expedient in ASC 606 that states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s contracts, each monthly delivery of product represents a separate performance obligation, therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company previously utilized the entitlements method to account for product imbalances, which is no longer applicable under ASC 606. The impact to the financial statements resulting from this change in accounting for production imbalances was not significant.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2018
STOCK-BASED COMPENSATION [Abstract]
STOCK-BASED COMPENSATION	10. STOCK‑BASED COMPENSATION Equity Incentive Plan —The 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 granted the authority to issue 1,325,000 shares of the Company’s common stock. During 2016, the 2013 Equity Plan was amended to include the authority to issue an additional 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 (“RSAs”), more than 150,000 restricted stock units (“RSUs”), more than 150,000 performance shares (“PSAs”) or more than 150,000 performance share units (“PSUs”) 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 RSAs, or more than 25,000 RSUs during any calendar year. As of December 31, 2018, 1,043,446 shares of common stock remained available for grant under the 2013 Equity Plan. At the Company’s annual meeting scheduled for May 2019, shareholders will vote on approval of an amendment to the 2013 Equity Plan which, if approved, will grant the authority to issue an additional 3,000,000 shares of the Company’s common stock. The Company grants service-based RSAs and RSUs to executive officers and employees, which generally vest ratably over a three-year service period. The Company also grants service-based RSAs to directors, which generally vest over a one-year service period. In addition, the Company grants PSAs and PSUs to executive officers that are subject to market-based vesting criteria, which generally vest over a three-year service period. The Company accounts for forfeitures of awards granted under these plans as they occur in determining compensation expense. The Company recognizes compensation expense for awards subject to market-based vesting conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense for share-settled awards is not reversed if vesting does not actually occur. During 2018, 2017 and 2016, 249,983, 538,194 and 737,912 shares, respectively, of service-based RSAs and RSUs were granted to employees, executive officers and directors under the 2013 Equity Plan. The Company determines compensation expense for these share-settled awards using their fair value at the grant date, which is based on the closing bid price of the Company’s common stock on such date. The weighted average grant date fair value of service-based RSAs and RSUs was $32.34 per share, $40.66 per share and $27.82 per share for the years ended December 31, 2018, 2017, and 2016, respectively. During 2018, 308,432 shares of service-based RSUs were granted to employees under the 2013 Equity Plan. These awards will be settled in cash and are recorded as a liability in the consolidated balance sheets. The Company determines compensation expense for cash-settled RSUs using the fair value at the end of each reporting period, which is based on the closing bid price of the Company’s common stock on such date. During 2018, 230,932 PSAs and PSUs subject to certain market-based vesting criteria were granted to executive officers under the 2013 Equity Plan. The 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 on each anniversary of the grant date over the three-year performance period. The number of awards earned could range from zero up to two times the number of shares initially granted. However, awards earned up to the target shares granted (or 100%) will be settled in shares, while awards earned in excess of the target shares granted will be settled in cash. The cash-settled component of such awards is recorded as a liability in the consolidated balance sheets and will be remeasured at fair value using a Monte Carlo valuation model at the end of each reporting period. During 2017 and 2016, 168,466 and 268,278 PSAs, 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 and will be settled entirely in shares. 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 is calculated based on the historical volatility and implied 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 these market-based awards were as follows: 2018 2017 2016 Number of simulations 2,500,000 2,500,000 2,500,000 Expected volatility 72.80% 82.44% 60.8% Risk-free interest rate 2.12% 1.52% 1.13% Dividend yield — — — The weighted average grant date fair value of the market-based awards that will be settled in shares as determined by the Monte Carlo valuation model was $27.28 per share, $63.04 per share and $25.56 per share in 2018, 2017 and 2016, respectively. The following table shows a summary of the Company’s service-based and market-based awards activity for the year ended December 31, 2018: Number of Awards Weighted Average Service ‑ Based Market-Based Grant Date RSAs & RSUs PSAs & PSUs Fair Value Nonvested awards, January 1 898,421 497,527 $ 45.55 Granted 249,983 230,932 29.91 Vested (461,982) - 41.98 Forfeited (131,895) (224,763) 60.59 Nonvested awards, December 31 554,527 503,696 $ 34.94 As of December 31, 2018, there was $13 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 1.7 years. For the years ended December 31, 2018, 2017 and 2016, the total fair value of the Company’s service-based and market-based awards vested was $16 million, $15 million and $5 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 2018, 2017 or 2016. 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, 2018 as well 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 1 122,034 $ 154.32 Granted - - Exercised (16,059) 47.01 $ 129 Forfeited or expired (56,745) 148.60 Options outstanding at December 31 49,230 $ 195.92 $ - Options vested at December 31 49,230 $ 195.92 $ - Options exercisable at December 31 49,230 $ 195.92 $ - There was no unrecognized compensation cost related to unvested stock option awards as of December 31, 2018. There were no stock options exercised during the years ended December 31, 2017 or 2016. Total stock-based compensation expense was $18 million, $22 million and $26 million for the years ended December 31, 2018, 2017 and 2016, respectively.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2018
INCOME TAXES [Abstract]
INCOME TAXES	11. INCOME TAXES Income tax expense (benefit) consists of the following (in thousands): Year Ended December 31, 2018 2017 2016 Current income tax expense (benefit) Federal $ - $ (7,305) $ (7,340) State - 14 150 Total current income tax benefit - (7,291) (7,190) Deferred income tax expense (benefit) Federal (10,960) (398,686) (65,130) State 12,333 (77,002) (15,326) Total deferred income tax expense (benefit) 1,373 (475,688) (80,456) Total $ 1,373 $ (482,979) $ (87,646) Income tax expense (benefit) differed from amounts that would result from applying the U.S. statutory income tax rate (21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016) to income before income taxes as follows (in thousands): Year Ended December 31, 2018 2017 2016 U.S. statutory income tax expense (benefit) $ 72,211 $ (602,219) $ (499,370) State income taxes, net of federal benefit 14,324 (39,557) (33,050) Valuation allowance (87,774) 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 Market-based equity awards 2,215 7,003 8,352 Enacted changes in state tax laws - - 5,020 Other 397 4,553 (2,163) Total $ 1,373 $ (482,979) $ (87,646) The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2018 and 2017 were as follows (in thousands): Year Ended December 31, 2018 2017 Deferred income tax assets Net operating loss carryforward $ 873,646 $ 828,617 Derivative instruments - 31,567 Asset retirement obligations 32,546 16,138 Restricted stock compensation 5,603 9,704 EOR credit carryforwards 7,946 7,946 Other 10,777 11,549 Total deferred income tax assets 930,518 905,521 Less valuation allowance (152,035) (271,300) Net deferred income tax assets 778,483 634,221 Deferred income tax liabilities Oil and gas properties 740,933 566,747 Trust distributions 15,479 54,980 Derivative instruments 16,375 - Discount on convertible senior notes 7,069 12,494 Total deferred income tax liabilities 779,856 634,221 Total net deferred income tax liabilities $ 1,373 $ - 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 (“NOLs”) 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, 2018, the Company had federal NOL carryforwards of $3.1 billion, which is 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 NOLs will expire between 2023 and 2037, and the state NOLs will expire between 2019 and 2037. 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, 2018, 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. On December 22, 2017, Congress passed the Tax Cuts and Jobs Act (the “TCJA”). The legislation significantly changed 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 subsequently issued Staff Accounting Bulletin No. 118, which allowed registrants to record provisional amounts during a one-year “measurement period” similar to that used to account for business combinations . The Company did not recognize any measurement period adjustments during 2018 and its accounting for the TCJA was complete as of December 31, 2018. 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 $51 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. Other elements of the TCJA that did not have an impact on the Company’s financial statements upon enactment of the TCJA, but may impact the Company’s income taxes in future periods include: (i) IRC Section 168(k) first-year optional bonus depreciation, (ii) repeal of the corporate alternative minimum tax, (iii) limitation on the usage of NOLs generated after 2017 to 80% of taxable income, (iv) additional limitations on certain meals and entertainment expenses, (v) repeal of the deduction for income attributable to domestic production activities, (vi) like-kind exchange limitations for property other than real property, (vii) ability to capitalize and amortize intangible drilling costs under IRC Section 59(e), and (viii) interest deduction limitations under IRC Section 163(j). In assessing the realizability of deferred tax assets (“DTAs”), management considers whether it is more likely than not that some portion, or all, of the Company’s DTAs 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 DTAs will not be realized, the tax asset is reduced by a valuation allowance. During 2018, the Company recorded an adjustment to its valuation allowance on DTAs totaling $30 million. At December 31, 2018, the Company had a valuation allowance totaling $152 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. At December 31, 2017, 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, $5 million of Canadian NOL carryforwards, $1 million of short-term capital loss carryforwards and $119 million in remaining net deferred tax assets that the Company determined were not likely to be realized as of December 31, 2017. As of December 31, 2018 and 2017, the Company did not have any uncertain tax positions. During the year ended December 31, 2016, the 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, 2018, 2017 and 2016, 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 2015 through 2018 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 2013 through 2018 tax years.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2018
EARNINGS PER SHARE [Abstract]
EARNINGS PER SHARE	12. EARNINGS PER SHARE The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data): Year Ended December 31, 2018 2017 2016 Basic Earnings (Loss) Per Share (1) Net income (loss) attributable to common shareholders $ 342,494 $ (1,237,648) $ (1,339,102) Weighted average shares outstanding, basic 90,953 90,683 62,967 Earnings (loss) per common share, basic $ 3.77 $ (13.65) $ (21.27) Diluted Earnings (Loss) Per Share (1) Net income (loss) attributable to common shareholders $ 342,494 $ (1,237,648) $ (1,339,102) Weighted average shares outstanding, basic 90,953 90,683 62,967 Service-based awards, market-based awards and stock options 916 - - Weighted average shares outstanding, diluted 91,869 90,683 62,967 Earnings (loss) per common share, diluted $ 3.73 $ (13.65) $ (21.27) (1) All share and per share amounts have been retroactively adjusted for the 2016 period 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, 2018, the diluted earnings per share calculation excludes the effect of 100,708 common shares for stock options that were out of the money as of December 31, 2018. 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 awards, 22,946 shares of market-based awards and 1,083 stock options. In addition, the diluted earnings per share calculation for the year ended December 31, 2017 excludes the effect of 123,775 common shares for stock options that were out-of-the-money and 345,071 shares of market-based awards that did not meet the 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 awards, 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 136,291 common shares for stock options that were out-of-the-money and 469,545 shares of market-based awards that did not meet the market-based vesting criteria as of December 31, 2016. Refer to the “Stock-Based Compensation” footnote for further information on the Company’s service-based awards, market-based awards and stock options. As discussed in the “Long-Term Debt” footnote, the Company has the option to settle conversions of the 2020 Convertible Senior Notes with cash, shares of common stock or any combination thereof. Based on the current conversion price, the entire outstanding principal amount of the 2020 Convertible Senior Notes as of December 31, 2018 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, 2018, 2017 and 2016, 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, 2018
COMMITMENTS AND CONTINGENCIES [Abstract]
COMMITMENTS AND CONTINGENCIES	13. COMMITMENTS AND CONTINGENCIES The table below shows the Company’s minimum future payments under non-cancelable leases and unconditional purchase obligations as of December 31, 2018 (in thousands): Payments due by period 2019 2020 2021 2022 2023 Thereafter Total Real estate leases $ 7,407 $ 4,770 $ 4,066 $ 4,188 $ 4,017 $ 25,140 $ 49,588 Pipeline transportation agreements 5,369 5,369 5,369 5,369 5,369 6,111 32,956 Drilling rig contracts 29,557 - - - - - 29,557 Automobile and equipment leases 4,216 3,422 1,678 488 35 - 9,839 Total $ 46,549 $ 13,561 $ 11,113 $ 10,045 $ 9,421 $ 31,251 $ 121,940 Real Estate Leases —The Company currently leases 222,900 square feet of administrative office space in Denver, Colorado under an agreement expiring in October 2019. The Company has entered into an agreement to lease 135,175 square feet of administrative office space in Denver beginning on or before November 1, 2019, which will replace its existing Denver office lease. In addition, Whiting leases 81,875 square feet of office and warehouse space in North Dakota through 2023 and 44,500 square feet of office space in Midland, Texas expiring in 2020. Rental expense for real estate leases for 2018, 2017 and 2016 amounted to $8 million, $8 million and $9 million, respectively. Minimum lease payments under the terms of non-cancelable real estate leases as of December 31, 2018 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. Pipeline Transportation Agreements — The Company has three agreements through 2025 with various third parties to facilitate the delivery of its produced oil, gas and NGLs to market. Under two of these contracts, the Company has committed to pay fixed monthly reservation fees on dedicated pipelines for natural gas and NGL transportation capacity, plus additional variable charges based on actual transportation volumes. These fixed monthly reservation fees totaling approximately $33 million have been included in the table above. The remaining contract contains a commitment to transport a minimum volume of crude oil 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, 2018, the Company estimated the minimum future commitments under this transportation agreement to approximate $13 million through 2022. During 2018, 2017 and 2016, transportation of crude oil, natural gas and NGLs under these contracts amounted to $5 million, $7 million and $5 million, respectively. Drilling Rig Contracts —As of December 31, 2018, the Company had five drilling rigs under short-term contracts expiring in 2019. The Company’s minimum drilling commitments under the terms of these contracts as of December 31, 2018 are shown in the table above. As of December 31, 2018, early termination of these contracts would require termination penalties of $22 million, which would be in lieu of paying the remaining drilling commitments under these contracts. During 2018, 2017 and 2016, the Company made payments of $33 million, $29 million and $31 million, respectively, under drilling rig 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. Automobile and Equipment Leases — The Company’s automobile and equipment leases consist of non-cancelable long-term lease agreements with various suppliers for vehicles utilized by its operations and field personnel and a variety of office and field equipment. Rental expense for automobile and equipment leases for 2018, 2017 and 2016 amounted to $5 million, $5 million, and $7 million, respectively. Minimum lease payments under the terms of these non-cancelable leases as of December 31, 2018 are shown in the table above. Purchase Contracts —The Company’s purchase obligations consist of take-or-pay arrangements to buy volumes of water for use in the fracture stimulation process. Under the terms of the agreements, the Company is obligated to purchase a minimum volume of water or else pay for any deficiencies at the prices stipulated in the contracts. Although minimum daily quantities are specified in the agreements, the actual water volumes purchased and their corresponding unit prices are variable over the terms of the contracts. As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above. As of December 31, 2018, the Company estimated the minimum future commitments under these purchase agreements to approximate $16 million through 2027. As a result of the Company’s reduced development operations in its Redtail field, Whiting has made and expects to make periodic deficiency payments u nder one of these purchase contracts during the remaining term, which expires in 2020. During 2018, 2017 and 2016, purchases of water under the Company’s take-or-pay arrangements amounted to $8 million, $22 million and $1 million, respectively, which included $2 million of deficiency payments for the year ended December 31, 2018 and insignificant deficiency payments for the year ended December 31, 2017. Water Disposal Agreement —The Company has a water disposal agreement expiring in 2024 under which 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 specified 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, 2018, the Company estimated the minimum future commitments under this disposal agreement to approximate $103 million 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 2018, 2017 and 2016, transportation and disposal of produced water amounted to $19 million, $16 million and $8 million, respectively, which includes $5 million, $4 million and $2 million of deficiency payments, respectively. Delivery Commitments —The Company has two 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 this delivery commitment, and therefore expects to avoid any payments for deficiencies under this contract. The remaining delivery contract is tied to crude oil production at Whiting’s Redtail field in Weld County, Colorado. As of December 31, 2018, this contract contains remaining delivery commitments of 16.0 MMBbl and 4.1 MMBbl of crude oil for the years ended December 31, 2019 and 2020, respectively. The Company has determined that it is not probable that future oil production from its Redtail field will be sufficient to meet the minimum volume requirements specified in these physical delivery contracts, and as a result, the Company expects to make periodic deficiency payments for any shortfalls in delivering the minimum committed volumes. During 2018, 2017 and 2016, total deficiency payments under these contracts, as well as a previous Redtail contract that was terminated in February 2018, amounted to $39 million, $66 million and $43 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, 2018 or 2017.

CAPITALIZED EXPLORATORY WELL CO

CAPITALIZED EXPLORATORY WELL COSTS	12 Months Ended
	Dec. 31, 2018
CAPITALIZED EXPLORATORY WELL COSTS [Abstract]
CAPITALIZED EXPLORATORY WELL COSTS	14. 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, 2018 2017 2016 Beginning balance at January 1 $ 13,894 $ - $ - Additions to capitalized exploratory well costs pending the determination of proved reserves 10,831 13,894 - Reclassifications to wells, facilities and equipment based on the determination of proved reserves (24,725) - - Capitalized exploratory well costs charged to expense - - - Ending balance at December 31 $ - $ 13,894 $ - At December 31, 2018, the Company had no costs capitalized for exploratory wells in progress for a period of greater than one year after the completion of drilling.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2018
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 and its consolidated subsidiaries. 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 statements of operations have been reclassified to conform to the current year presentation. These include the reclassification of gathering, transportation, compression and other expenses and ad valorem taxes from previously reported lease operating expenses in the consolidated statements of operations. For all periods presented, gathering, transportation, compression and other expenses are presented as a separate caption and ad valorem taxes are combined with production taxes. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
Cash and Cash Equivalents	Cash and Cash Equivalents —Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less. Restricted cash at December 31, 2016 related to a deposit received in connection with the sale of Whiting’s interests in the Robinson Lake and Belfield gas processing plants in North Dakota. 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 “Acquisitions and Divestitures” footnote for further information on this transaction.
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, 2018 and 2017, the Company had an allowance for doubtful accounts of $12 million and $17 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 $23 million and $24 million as of December 31, 2018 and 2017, 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 $5 million and $7 million as of December 31, 2018 and 2017, 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 undiscounted 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 $835 million for the year ended December 31, 2017, 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. 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 $37 million, $59 million and $73 million for the years ended December 31, 2018, 2017 and 2016, 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. Costs 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.
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 —Revenues are predominantly derived from the sale of produced oil, NGLs and natural gas. In May 2014, the FASB issued Accounting Standards Update No. 2014‑09, Revenue from Contracts with Customers (“ASU 2014‑09”). The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB ASC Topic 606 – Revenue from Contracts with Customers (“ASC 606”). The objective of ASC 606 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASC 606 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard permits 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 adopted ASC 606 effective January 1, 2018 using the modified retrospective approach. The adoption did not have an impact on the Company’s net income or cash flows, and the Company did not record a cumulative-effect adjustment to retained earnings as a result. However, the adoption did result in changes to the classification of certain fees incurred under pipeline gathering and transportation agreements and gas processing agreements, as well as certain costs attributable to non-operated properties, which led to an overall decrease in total revenues with a corresponding decrease in gathering, transportation, compression and other expenses under the new standard. Refer to the “Revenue Recognition” footnote for further information on the Company’s implementation of this standard. In accordance with ASC 606, oil and gas revenues are recognized when the performance obligation to deliver the product is met and control is transferred to the customer. Payments for product sales are received one to three months after delivery. At the end of each month when the performance obligation is satisfied and the amount of production delivered and the price received can be reasonably estimated, amounts due from customers are accrued in accounts receivable trade, net in the consolidated balance sheets. Variances between estimated revenue and actual payments are recorded in the month the payment is received. However, differences have been and are insignificant. 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, performance shares, performance share units and stock options, to employees and non-employee directors. The Company determines compensation expense for share-settled awards 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 awards granted under these plans based on the fair value of such awards at the end of each reporting period. Cash-settled awards are recorded as a liability in the consolidated balance sheets, and gains and losses from changes in fair value 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 2018, 2017 and 2016 were $7 million, $8 million and $8 million, respectively. Employees vest in employer contributions at 20% per year of completed service up to five years.
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 and performance 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, 2018, 2017 and 2016. Year Ended December 31, 2018 United Energy Trading, LLC 17 % Tesoro Crude Oil Co 14 % Philips 66 Company 11 % 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 eleven counterparties, all of which are participants in Whiting’s credit facility and all of which have investment-grade ratings from Moody’s and Standard & Poor’s. As of December 31, 2018, outstanding derivative contracts with JP Morgan Chase Bank, N.A., Wells Fargo Bank, N.A. and Capital One, N.A. represented 18%, 15% and 15%, respectively, of total crude oil volumes hedged.
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements — 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. The FASB subsequently issued various ASUs which provided additional implementation guidance. ASU 2016‑02 and its amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The standard permits retrospective application through recognition of a cumulative-effect adjustment at the beginning of either the earliest reporting period presented or the period of adoption. The Company adopted ASU 2016-02 effective January 1, 2019 using a cumulative-effect adjustment as of the adoption date. Whiting elected certain practical expedients available under the standard including those that permit the Company to not (i) reassess prior conclusions reached under FASB ASC Topic 840 – Leases for lease identification, lease classification and initial direct costs, (ii) evaluate existing or expired land easements under the new standard and (iii) separate lease and non-lease components contained within a single agreement. Additionally, the Company has elected the short-term lease recognition exemption and therefore, leases with a term of one year or less will not be recognized on the consolidated balance sheet. Whiting is substantially complete with the assessment of its existing accounting policies and documentation, implementation of lease accounting software and enhancement of its internal controls. Adoption of the standard will result in the recognition of additional lease assets and liabilities on Whiting’s consolidated balance sheet as well as additional disclosures. The adoption is not expected to have a material impact to the Company’s consolidated statement of operations. As of December 31, 2018, the Company had approximately $254 million of contractual obligations related to its water disposal agreements, purchase obligations, pipeline transportation agreements, drilling rig contracts, real estate leases and automobile and equipment leases, and certain of these contracts will be recorded on its consolidated balance sheet under this standard.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2018
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
Percentages of total oil and gas sales to significant purchasers	Year Ended December 31, 2018 United Energy Trading, LLC 17 % Tesoro Crude Oil Co 14 % Philips 66 Company 11 % 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, 2018
OIL AND GAS PROPERTIES [Abstract]
Net capitalized costs related to oil and gas producing activities	Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2018 and 2017 are as follows (in thousands): December 31, 2018 2017 Proved leasehold costs $ 2,729,593 $ 2,622,576 Unproved leasehold costs 122,687 137,694 Costs of completed wells and facilities 9,182,384 8,288,591 Wells and facilities in progress 160,995 244,789 Total oil and gas properties, successful efforts method 12,195,659 11,293,650 Accumulated depletion (4,937,579) (4,185,301) Oil and gas properties, net $ 7,258,080 $ 7,108,349

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2018
ACQUISITIONS AND DIVESTITURES [Abstract]
Schedule of purchase price allocation	As the purchase price is further adjusted for post-close adjustments and as oil and gas property valuations are completed, the final purchase price allocation may result in a different allocation to the tangible assets from that which is presented in the table below (in thousands): Cash consideration $ 126,938 Fair value of assets and liabilities acquired: Proved oil and gas properties $ 107,701 Unproved oil and gas properties 21,769 Total fair value of oil and gas properties acquired 129,470 Asset retirement obligations 2,532 Total fair value of net assets acquired $ 126,938

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2018
LONG-TERM DEBT [Abstract]
Schedule of long-term debt	Long-term debt, including the current portion, consisted of the following at December 31, 2018 and 2017 (in thousands): December 31, 2018 2017 5.0% Senior Notes due 2019 $ - $ 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 1,000,000 Total principal 2,843,980 3,805,389 Unamortized debt discounts and premiums (28,994) (50,945) Unamortized debt issuance costs on notes (22,665) (31,015) Total debt 2,792,321 3,723,429 Less current portion of long-term debt - (958,713) Total long-term debt $ 2,792,321 $ 2,764,716
Schedule of five succeeding fiscal years of scheduled maturities for the Company's long-term debt	The following table shows five succeeding fiscal years of anticipated maturities for the Company’s long-term debt as of December 31, 2018 (in thousands): 2019 2020 2021 2022 2023 Long-term debt $ - $ 562,075 $ 873,609 $ - $ 408,296
Summary of margin rates and commitment fees	Applicable Applicable Margin for Base Margin for Commitment Ratio of Outstanding Borrowings to Borrowing Base Rate Loans Eurodollar Loans Fee Less than 0.25 to 1.0 0.50% 1.50% 0.375% Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 0.75% 1.75% 0.375% Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 1.00% 2.00% 0.50% Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 1.25% 2.25% 0.50% Greater than or equal to 0.90 to 1.0 1.50% 2.50% 0.50%
Summary of senior notes and convertible senior notes	The following table summarizes the material terms of the Company’s senior notes and convertible senior notes outstanding at December 31, 2018: 2020 Convertible 2021 2023 2026 Senior Notes Senior Notes Senior Notes Senior Notes Outstanding principal (in thousands) $ 562,075 $ 873,609 $ 408,296 $ 1,000,000 Interest rate 1.25% 5.75% 6.25% 6.625% Maturity date Apr 1, 2020 Mar 15, 2021 Apr 1, 2023 Jan 15, 2026 Interest payment dates Apr 1, Oct 1 Mar 15, Sep 15 Apr 1, Oct 1 Jan 15, Jul 15 Make-whole redemption date (1) N/A (2) Dec 15, 2020 Jan 1, 2023 Oct 15, 2025 (1) 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. (2) 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	The 2020 Convertible Senior Notes consisted of the following at December 31, 2018 and 2017 (in thousands): December 31, 2018 2017 Liability component Principal $ 562,075 $ 562,075 Less: unamortized note discount (29,504) (51,666) Less: unamortized debt issuance costs (2,340) (4,178) Net carrying value $ 530,231 $ 506,231 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, 2018 and 2017.

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2018
ASSET RETIREMENT OBLIGATIONS [Abstract]
Schedule of reconciliation of the Company's asset retirement obligations	The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2018 and 2017 (in thousands): December 31, 2018 2017 Asset retirement obligation at January 1 $ 134,237 $ 177,004 Additional liability incurred 11,981 7,727 Revisions to estimated cash flows (1) (17,197) (52,947) Accretion expense 11,405 13,809 Obligations on sold properties (676) (6,988) Liabilities settled (3,916) (4,368) Asset retirement obligation at December 31 $ 135,834 $ 134,237 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 INSTRUME_2

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
DERIVATIVE FINANCIAL INSTRUMENTS [Abstract]
Derivative instruments	The table below details the Company’s costless collar derivatives entered into to hedge forecasted crude oil production revenues as of December 31, 2018. Derivative Contracted Crude Weighted Average NYMEX Price Instrument Period Oil Volumes (Bbl) for Crude Oil (per Bbl) Collars (1) Jan - Dec 2019 9,900,000 $51.21 - $77.14 Total 9,900,000 (1) Subsequent to December 31, 2018, the Company entered into swap contracts for 900,000 Bbl of crude oil volumes and additional costless collars for 900,000 Bbl of crude oil volumes for the second half of 2019.
Schedule of effects of commodity derivative instruments	The following table summarizes the effects of derivative instruments on the consolidated statements of operations for the years ended December 31, 2018, 2017 and 2016 (in thousands): (Gain) Loss Recognized in Income Not Designated as Statement of Operations Year Ended December 31, ASC 815 Hedges Classification 2018 2017 2016 Commodity contracts Derivative (gain) loss, net $ 17,170 $ 104,138 $ 58,771 Embedded derivatives Derivative (gain) loss, net - 18,709 (59,358) Total $ 17,170 $ 122,847 $ (587)
Location and fair value of derivative instruments	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, 2018 (1) Net Gross Recognized Recognized Gross Fair Value Not Designated as Assets/ Amounts Assets/ ASC 815 Hedges Balance Sheet Classification Liabilities Offset Liabilities Derivative assets Commodity contracts - current Derivative assets $ 69,735 $ (1,393) $ 68,342 Total derivative assets $ 69,735 $ (1,393) $ 68,342 Derivative liabilities Commodity contracts - current Derivative liabilities $ 1,393 $ (1,393) $ - Total derivative liabilities $ 1,393 $ (1,393) $ - 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 Derivative assets $ 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 (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 (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
FAIR VALUE MEASUREMENTS [Abstract]
Summary of the fair values and carrying value of debt instruments	The following table summarizes the fair values and carrying values of these instruments as of December 31, 2018 and 2017 (in thousands): December 31, 2018 December 31, 2017 Fair Carrying Fair Carrying Value (1) Value (2) Value (1) Value (2) 5.0% Senior Notes due 2019 $ - $ - $ 985,444 $ 958,713 1.25% Convertible Senior Notes due 2020 531,161 530,231 517,109 506,231 5.75% Senior Notes due 2021 829,929 870,545 897,633 869,284 6.25% Senior Notes due 2023 375,632 404,659 418,503 403,940 6.625% Senior Notes due 2026 865,000 986,886 1,025,000 985,261 Total $ 2,601,722 $ 2,792,321 $ 3,843,689 $ 3,723,429 (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	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, 2018 and 2017, 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, 2018 Financial Assets Commodity derivatives – current $ - $ 68,342 $ - $ 68,342 Total financial assets $ - $ 68,342 $ - $ 68,342 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
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy	The 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, 2018 and 2017 (in thousands): Year Ended December 31, 2018 2017 Fair value liability, beginning of period $ (63,278) $ (9,214) Unrealized gains (losses) on commodity derivative contracts included in earnings (1) 2,242 (54,064) Settlement of commodity derivative contracts 61,036 - Transfers into (out of) Level 3 - - Fair value liability, end of period $ - $ (63,278) (1) Included in derivative (gain) loss, net in the consolidated statements of operations.
Non-financial assets and liabilities measured at fair value on a nonrecurring basis	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 million which was recorded within exploration and impairment expense.

SHAREHOLDERS_ EQUITY AND NONC_2

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST (Tables)	12 Months Ended
	Dec. 31, 2018
SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST [Abstract]
Schedule of noncontrolling interest	The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands): Year Ended December 31, 2017 Balance at beginning of period $ 7,962 Net loss (14) Conveyance of ownership interest (7,948) Balance at end of period $ -

REVENUE RECOGNITION (Tables)

REVENUE RECOGNITION (Tables)	12 Months Ended
	Dec. 31, 2018
REVENUE RECOGNITION [Abstract]
Revenue Recognition Reclassification	Such reclassification led to an overall decrease in total revenues with a corresponding decrease in gathering, transportation, compression and other expenses (“GTC”) as follows (in thousands): Year Ended December 31, 2018 Under Under ASC 606 ASC 605 Difference OPERATING REVENUES Oil sales $ 1,850,052 $ 1,834,727 $ 15,325 NGL and natural gas sales 231,362 288,174 (56,812) Oil, NGL and natural gas sales $ 2,081,414 $ 2,122,901 $ (41,487) OPERATING EXPENSES Gathering, transportation, compression and other $ 48,105 $ 89,592 $ (41,487) Total operating expenses $ 1,511,535 $ 1,553,022 $ (41,487) INCOME FROM OPERATIONS $ 569,879 $ 569,879 $ -

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2018
STOCK-BASED COMPENSATION [Abstract]
Assumption for valuing market based restricted shares	2018 2017 2016 Number of simulations 2,500,000 2,500,000 2,500,000 Expected volatility 72.80% 82.44% 60.8% Risk-free interest rate 2.12% 1.52% 1.13% Dividend yield — — —
Summary of nonvested shares	Number of Awards Weighted Average Service ‑ Based Market-Based Grant Date RSAs & RSUs PSAs & PSUs Fair Value Nonvested awards, January 1 898,421 497,527 $ 45.55 Granted 249,983 230,932 29.91 Vested (461,982) - 41.98 Forfeited (131,895) (224,763) 60.59 Nonvested awards, December 31 554,527 503,696 $ 34.94
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 1 122,034 $ 154.32 Granted - - Exercised (16,059) 47.01 $ 129 Forfeited or expired (56,745) 148.60 Options outstanding at December 31 49,230 $ 195.92 $ - Options vested at December 31 49,230 $ 195.92 $ - Options exercisable at December 31 49,230 $ 195.92 $ -

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2018
INCOME TAXES [Abstract]
Schedule of income tax expense	Income tax expense (benefit) consists of the following (in thousands): Year Ended December 31, 2018 2017 2016 Current income tax expense (benefit) Federal $ - $ (7,305) $ (7,340) State - 14 150 Total current income tax benefit - (7,291) (7,190) Deferred income tax expense (benefit) Federal (10,960) (398,686) (65,130) State 12,333 (77,002) (15,326) Total deferred income tax expense (benefit) 1,373 (475,688) (80,456) Total $ 1,373 $ (482,979) $ (87,646)
Reconciliation of statutory income tax expense to income tax expense	Income tax expense (benefit) differed from amounts that would result from applying the U.S. statutory income tax rate (21% for the year ended December 31, 2018 and 35% for the years ended December 31, 2017 and 2016) to income before income taxes as follows (in thousands): Year Ended December 31, 2018 2017 2016 U.S. statutory income tax expense (benefit) $ 72,211 $ (602,219) $ (499,370) State income taxes, net of federal benefit 14,324 (39,557) (33,050) Valuation allowance (87,774) 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 Market-based equity awards 2,215 7,003 8,352 Enacted changes in state tax laws - - 5,020 Other 397 4,553 (2,163) Total $ 1,373 $ (482,979) $ (87,646)
Components of deferred income tax assets and liabilities	The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2018 and 2017 were as follows (in thousands): Year Ended December 31, 2018 2017 Deferred income tax assets Net operating loss carryforward $ 873,646 $ 828,617 Derivative instruments - 31,567 Asset retirement obligations 32,546 16,138 Restricted stock compensation 5,603 9,704 EOR credit carryforwards 7,946 7,946 Other 10,777 11,549 Total deferred income tax assets 930,518 905,521 Less valuation allowance (152,035) (271,300) Net deferred income tax assets 778,483 634,221 Deferred income tax liabilities Oil and gas properties 740,933 566,747 Trust distributions 15,479 54,980 Derivative instruments 16,375 - Discount on convertible senior notes 7,069 12,494 Total deferred income tax liabilities 779,856 634,221 Total net deferred income tax liabilities $ 1,373 $ -

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2018
EARNINGS PER SHARE [Abstract]
Reconciliations between basic and diluted earnings per share	The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data): Year Ended December 31, 2018 2017 2016 Basic Earnings (Loss) Per Share (1) Net income (loss) attributable to common shareholders $ 342,494 $ (1,237,648) $ (1,339,102) Weighted average shares outstanding, basic 90,953 90,683 62,967 Earnings (loss) per common share, basic $ 3.77 $ (13.65) $ (21.27) Diluted Earnings (Loss) Per Share (1) Net income (loss) attributable to common shareholders $ 342,494 $ (1,237,648) $ (1,339,102) Weighted average shares outstanding, basic 90,953 90,683 62,967 Service-based awards, market-based awards and stock options 916 - - Weighted average shares outstanding, diluted 91,869 90,683 62,967 Earnings (loss) per common share, diluted $ 3.73 $ (13.65) $ (21.27) (1) All share and per share amounts have been retroactively adjusted for the 2016 period 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, 2018
COMMITMENTS AND CONTINGENCIES [Abstract]
Minimum future payments under non-cancelable operating leases and unconditional purchase obligations	The table below shows the Company’s minimum future payments under non-cancelable leases and unconditional purchase obligations as of December 31, 2018 (in thousands): Payments due by period 2019 2020 2021 2022 2023 Thereafter Total Real estate leases $ 7,407 $ 4,770 $ 4,066 $ 4,188 $ 4,017 $ 25,140 $ 49,588 Pipeline transportation agreements 5,369 5,369 5,369 5,369 5,369 6,111 32,956 Drilling rig contracts 29,557 - - - - - 29,557 Automobile and equipment leases 4,216 3,422 1,678 488 35 - 9,839 Total $ 46,549 $ 13,561 $ 11,113 $ 10,045 $ 9,421 $ 31,251 $ 121,940

CAPITALIZED EXPLORATORY WELL _2

CAPITALIZED EXPLORATORY WELL COSTS (Tables)	12 Months Ended
	Dec. 31, 2018
CAPITALIZED EXPLORATORY WELL COSTS [Abstract]
Net changes in 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, 2018 2017 2016 Beginning balance at January 1 $ 13,894 $ - $ - Additions to capitalized exploratory well costs pending the determination of proved reserves 10,831 13,894 - Reclassifications to wells, facilities and equipment based on the determination of proved reserves (24,725) - - Capitalized exploratory well costs charged to expense - - - Ending balance at December 31 $ - $ 13,894 $ -

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative I) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Summary Of Significant Accounting Policies [Line Items]
Oil and gas receivables collection period	2 months
Allowance for doubtful account	$ 12	$ 17
Materials and supplies inventories	23	24
Oil in tanks	5	7
Impairment of Proved Properties		835
Impairment of Unproved Properties	$ 37	$ 59	$ 73
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life	4 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life	30 years

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative II) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)segmentshares	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Summary Of Significant Accounting Policies [Line Items]
Employer's contribution in employees retirement plan | $	$ 7	$ 8	$ 8
Employees vest in employer contribution Percentage, per year of completed service	20.00%
Service period	5 years
Number of operating segments | segment	1
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

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Credit risk) (Details) - item	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Credit Concentration Risk [Member] | Oil And Gas Sales [Member] | United Energy Trading, LLC [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	17.00%
Credit Concentration Risk [Member] | Oil And Gas Sales [Member] | Tesoro Crude Oil Co [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	14.00%	18.00%	15.00%
Credit Concentration Risk [Member] | Oil And Gas Sales [Member] | Philips 66 Company [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	11.00%
Credit Concentration Risk [Member] | Oil And Gas Sales [Member] | Jamex Marketing LLC [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue			12.00%
Commodity Price Risk [Member] | Derivative Contracts [Member]
Concentration Risk [Line Items]
Number of counterparties	11
Commodity Price Risk [Member] | Derivative Contracts [Member] | JP Morgan Chase [Member]
Concentration Risk [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged	18.00%
Commodity Price Risk [Member] | Derivative Contracts [Member] | Wells Fargo Bank [Member]
Concentration Risk [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged	15.00%
Commodity Price Risk [Member] | Derivative Contracts [Member] | Capital One, N. A. [Member]
Concentration Risk [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged	15.00%

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Pronouncements) (Details) $ in Thousands	Dec. 31, 2018USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contractual obligation	$ 121,940
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contractual obligation	$ 254,000

OIL AND GAS PROPERTIES (Details

OIL AND GAS PROPERTIES (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
OIL AND GAS PROPERTIES [Abstract]
Proved leasehold costs	$ 2,729,593	$ 2,622,576
Unproved leasehold costs	122,687	137,694
Costs of completed wells and facilities	9,182,384	8,288,591
Wells and facilities in progress	160,995	244,789
Total oil and gas properties, successful efforts method	12,195,659	11,293,650
Accumulated depletion	(4,937,579)	(4,185,301)
Oil and gas properties, net	$ 7,258,080	$ 7,108,349

ACQUISITIONS AND DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES (Acquisition) (Details) $ in Thousands	Jul. 31, 2018USD ($)aitem	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Business Acquisition [Line Items]
Cash consideration		$ 142,723	$ 21,429	$ 4,718
Richland and McKenzie Counties [Member]
Business Acquisition [Line Items]
Aggregate purchase price	$ 130,000
Net acquisition area (in acres) | a	54,800
Number of wells acquired | item	117
Cash consideration	$ 126,938
Proved oil and gas properties	107,701
Unproved oil and gas properties	21,769
Total fair value of oil and gas properties acquired	129,470
Asset retirement obligations	2,532
Total fair value of net assets acquired	$ 126,938

ACQUISITIONS AND DIVESTITURES_3

ACQUISITIONS AND DIVESTITURES (Divestitures) (Details)	Sep. 01, 2017USD ($)	Jul. 19, 2017USD ($)	Jan. 01, 2017USD ($)	Jul. 31, 2016USD ($)$ / bbl	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Dispositions
Proceeds from sale of oil and gas properties					$ 4,746,000	$ 929,974,000	$ 313,355,000
Embedded derivatives [Member]
Dispositions
Additional proceeds from disposal for specified period for each $0.01 average NYMEX futures is above threshold price per Bbl				$ 100,000
Incremental price per Bbl threshold for additional proceeds from sale | $ / bbl				0.01
Maximum possible additional proceeds from divestiture of business				$ 100,000,000
Amount received from settled contingent payment		$ 35,000,000
North Ward Estes Properties [Member] | Embedded derivatives [Member]
Dispositions
Average price per Bbl threshold for additional proceeds from sale | $ / bbl				50
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Robinson Lake Gas Processing Plant and Belfield Gas Processing Plant [Member]
Dispositions
Proceeds from sale of oil and gas properties			$ 375,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Robinson Lake Gas Processing Plant [Member]
Dispositions
Sale of interest in gas processing plant			50.00%
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Belfield Gas Processing Plant [Member]
Dispositions
Sale of interest in gas processing plant			50.00%
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Fort Berthold Indian Reservation Area [Member]
Dispositions
Proceeds from sale of oil and gas properties	$ 500,000,000
Gain (loss) on sale	$ (402,000,000)
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | North Ward Estes Properties [Member]
Dispositions
Proceeds from sale of oil and gas properties				$ 300,000,000
Gain (loss) on sale		3,000,000		(187,000,000)
Additional proceeds from disposal for specified period for each $0.01 average NYMEX futures is above threshold price per Bbl				$ 100,000
Incremental price per Bbl threshold for additional proceeds from sale | $ / bbl				0.01
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

LONG-TERM DEBT (Schedule of lon

LONG-TERM DEBT (Schedule of long-term debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2015	Sep. 30, 2013
Debt Instrument [Line Items]
Total principal	$ 2,843,980		$ 3,805,389
Unamortized debt discounts and premiums	(28,994)		(50,945)
Unamortized debt issuance costs on notes	(22,665)		(31,015)
Total debt	2,792,321		3,723,429
Less current portion of long-term debt			(958,713)
Total long-term debt	$ 2,792,321		2,764,716
5.0% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Total principal		$ 0	961,409
Interest rate on debt instrument (as a percent)	5.00%				5.00%
1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Total principal	$ 562,075		562,075
Unamortized debt issuance costs on notes	$ (2,340)		(4,178)	$ (25,000)
Interest rate on debt instrument (as a percent)	1.25%			1.25%
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%
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%
6.625% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Total principal	$ 1,000,000		$ 1,000,000
Interest rate on debt instrument (as a percent)	6.625%		6.625%

LONG-TERM DEBT (Scheduled matur

LONG-TERM DEBT (Scheduled maturities for long-term debt) (Details) $ in Thousands	Dec. 31, 2018USD ($)
LONG-TERM DEBT [Abstract]
2,020	$ 562,075
2,021	873,609
2,023	$ 408,296

LONG-TERM DEBT (Credit agreemen

LONG-TERM DEBT (Credit agreement) (Details) - Credit Agreement [Member] $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Debt Instrument [Line Items]
Maximum borrowing capacity of credit facility	$ 2,400
Maximum aggregate commitments	1,750
Borrowing capacity of credit facility, net of letter of credit	1,750
Outstanding borrowings under credit facility	0
Letters of credit borrowings outstanding	2
Portion of line of credit available for issuance of letters of credit	50
Amount of revolving credit agreement available for additional letters of credit under the agreement	$ 48
Base Rate [Member]
Debt Instrument [Line Items]
Basis points added to reference rate (as a percent)	0.50%
LIBOR [Member]
Debt Instrument [Line Items]
Basis points added to reference rate (as a percent)	1.00%

LONG-TERM DEBT (Margin rates an

LONG-TERM DEBT (Margin rates and commitment fees) (Details) - Credit Agreement [Member]	12 Months Ended
	Dec. 31, 2018USD ($)
Debt Instrument [Line Items]
Retained earnings free from restrictions	$ 0
Minimum consolidated current assets to consolidated current liabilities ratio	1
Total debt to EBITDAX ratio	4
Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	0.50%
Less than 0.25 to 1.0 [Member]
Debt Instrument [Line Items]
Range, less than	0.25
Commitment Fee (as a percent)	0.375%
Less than 0.25 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	0.50%
Less than 0.25 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.50%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member]
Debt Instrument [Line Items]
Range, greater than or equal to	0.25
Range, less than	0.50
Commitment Fee (as a percent)	0.375%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	0.75%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.75%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member]
Debt Instrument [Line Items]
Range, greater than or equal to	0.50
Range, less than	0.75
Commitment Fee (as a percent)	0.50%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.00%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	2.00%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member]
Debt Instrument [Line Items]
Range, greater than or equal to	0.75
Range, less than	0.90
Commitment Fee (as a percent)	0.50%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.25%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	2.25%
Greater than or equal to 0.90 to 1.0 [Member]
Debt Instrument [Line Items]
Range, greater than or equal to	0.90
Commitment Fee (as a percent)	0.50%
Greater than or equal to 0.90 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.50%
Greater than or equal to 0.90 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	2.50%

LONG-TERM DEBT (Summary of seni

LONG-TERM DEBT (Summary of senior notes and convertible senior notes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Mar. 31, 2015
Debt Instrument [Line Items]
Carrying value of debt instrument	$ 2,843,980	$ 3,805,389
Percentage of redemption price	100.00%
1.25% Convertible Senior Notes due 2020 [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%
Debt maturity date	Apr. 1, 2020
5.75% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Carrying value of debt instrument	$ 873,609	873,609
Interest rate on debt instrument (as a percent)	5.75%
Debt maturity date	Mar. 15, 2021
Make-whole redemption date	Dec. 15, 2020
6.25% Senior Notes due 2023 [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%
Debt maturity date	Apr. 1, 2023
Make-whole redemption date	Jan. 1, 2023
6.625% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Carrying value of debt instrument	$ 1,000,000	$ 1,000,000
Interest rate on debt instrument (as a percent)	6.625%	6.625%
Debt maturity date	Jan. 15, 2026
Make-whole redemption date	Oct. 15, 2025

LONG-TERM DEBT (Senior notes an

LONG-TERM DEBT (Senior notes and senior subordinated notes) (Details) - USD ($) $ in Thousands, shares in Millions	Jan. 26, 2018	Feb. 02, 2017	Jul. 01, 2016	Jul. 31, 2016	Mar. 31, 2016	Jul. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2015	Sep. 30, 2013	Sep. 30, 2010
Debt Instrument [Line Items]
Cash charge related to the redemption premium											$ 41,919
Percentage of redemption price									100.00%
Gain (loss) on extinguishment of debt									$ (31,968)	$ (1,540)	(42,236)
Non cash charges						$ 113,000
Total principal									2,843,980	$ 3,805,389
Repurchase of notes									$ 990,023
Senior Subordinated Notes And Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged			$ 405,000		$ 477,000
Gain (loss) on extinguishment of debt											91,000
Non cash charges											4,000
6.5% Senior Subordinated Notes due 2018 [Member]
Debt Instrument [Line Items]
Notes Issued																$ 350,000
Interest rate on debt instrument (as a percent)									6.50%	6.50%						6.50%
Notes repurchased, principal amount		$ 275,000
Percentage of redemption price		100.00%
Aggregate principal amount exchanged			26,000		49,000
Gain (loss) on extinguishment of debt		$ (2,000)
Total principal													$ 0
Repurchase of notes		$ 281,000
5.0% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Notes Issued															$ 1,100,000
Interest rate on debt instrument (as a percent)									5.00%						5.00%
Notes repurchased, principal amount	$ 961,000
Percentage of redemption price	102.976%
Aggregate principal amount exchanged			42,000		97,000
Gain (loss) on extinguishment of debt	$ (31,000)
Total principal										$ 961,409		$ 0
Repurchase of notes	$ 1,000,000
5.75% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Interest rate on debt instrument (as a percent)									5.75%
Aggregate principal amount exchanged			174,000		152,000
Total principal									$ 873,609	873,609
5.75% Senior Notes due 2021, Par [Member]
Debt Instrument [Line Items]
Notes Issued															$ 800,000
Interest rate on debt instrument (as a percent)															5.75%
5.75% Senior Notes due 2021, Premium [Member]
Debt Instrument [Line Items]
Notes Issued															$ 400,000
Interest rate on debt instrument (as a percent)															5.75%
Premium as a percentage of par															101.00%
Debt, effective interest rate									5.50%
6.25% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Notes Issued														$ 750,000
Interest rate on debt instrument (as a percent)									6.25%					6.25%
Aggregate principal amount exchanged			$ 163,000		179,000
Total principal									$ 408,296	408,296
6.625% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Notes Issued										$ 1,000,000
Interest rate on debt instrument (as a percent)									6.625%	6.625%
Total principal									$ 1,000,000	$ 1,000,000
New Convertible Notes [Member]
Debt Instrument [Line Items]
Notes Issued					477,000
Gain (loss) on extinguishment of debt							$ (188,000)
Fair value difference from principal amount					95,000
Unamortized debt discount					185,000
Fair value of embedded derivatives for conversion options					$ 90,000
Aggregate principal amount converted into shares							$ 477,000
Number of shares upon settlement of conversion							10.5
Cash paid for early conversion of notes, including accrued and unpaid interest							$ 46,000
Total principal							$ 0
Mandatory Convertible Notes [Member]
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt								$ (1,000)
Non cash charges								259,000
Fair value difference from principal amount				$ 69,000
Unamortized debt discount				$ 302,000		$ 302,000
Aggregate principal amount converted into shares								$ 1,093,000
Number of shares upon settlement of conversion								28.9
Total principal								$ 0			$ 0

LONG-TERM DEBT (2020 Convertibl

LONG-TERM DEBT (2020 Convertible senior notes) (Details) $ / shares in Units, $ in Thousands	Jul. 01, 2016USD ($)	Jun. 29, 2016USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2018USD ($)item$ / shares$ / item	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
Debt finance cost				$ 22,665	$ 31,015
Carrying value of debt instrument				2,843,980	3,805,389
1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Principal			$ 1,250,000	$ 562,075	562,075
Interest rate on debt instrument (as a percent)			1.25%	1.25%
Net proceeds			$ 1,200,000
Debt finance cost			25,000	$ 2,340	4,178
Aggregate principal amount exchanged	$ 559,000	$ 129,000
Carrying value of debt instrument				$ 562,075	562,075
Minimum days within 30 consecutive days of trading, where percent of conversion price exceed agreed upon percentage | item				20
Consecutive trading days | item				30
Conversion ratio				0.0064102
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
Debt discount			$ 238,000	$ 29,504	$ 51,666
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes Conversion Scenario1 [Member]
Debt Instrument [Line Items]
Minimum conversion price percentage used to determine settlement of conversion				130.00%
1.25% Convertible Senior Notes due 2020 [Member] | Convertible Senior Notes Conversion Scenario2 [Member]
Debt Instrument [Line Items]
Period after measurement period used for convertible senior notes				5 days
Debt Instruments Convertible Threshold Consecutive Trading Days				5 days
Principal amount per conversion ratio | $ / item				1,000
Threshold percentage of product of stock price and conversion rate				98.00%

LONG-TERM DEBT (Schedule of con

LONG-TERM DEBT (Schedule of convertible senior notes) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Mar. 31, 2015
Debt Instrument [Line Items]
Less: unamortized debt issuance costs	$ (22,665)	$ (31,015)
Interest expense	197,474	191,088	$ 557,620
1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Principal	562,075	562,075		$ 1,250,000
Less: unamortized note discount	(29,504)	(51,666)		(238,000)
Less: unamortized debt issuance costs	(2,340)	(4,178)		$ (25,000)
Net carrying value	530,231	506,231
Interest expense	29,000	28,000	$ 43,000
Equity Component Of Convertible Senior Note [Member]
Debt Instrument [Line Items]
Less: unamortized debt issuance costs	(5,000)	(5,000)
Equity component	136,522	136,522
Equity component of convertible debt, deferred taxes	$ 50,000	$ 50,000

LONG-TERM DEBT (Mandatory conve

LONG-TERM DEBT (Mandatory convertible notes, security and guarantees) (Details) - USD ($) $ in Thousands, shares in Millions	Jan. 26, 2018	Feb. 02, 2017	Jul. 01, 2016	Jun. 29, 2016	Jul. 31, 2016	Mar. 31, 2016	Jul. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2015
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt										$ (31,968)	$ (1,540)	$ (42,236)
Non cash charges							$ 113,000
Adjustment to equity component of 2020 Convertible Senior Notes upon extinguishment, net												(63,330)
Recognition of beneficial conversion features on convertible notes												232,801
Carrying value of debt instrument										$ 2,843,980	3,805,389
Percentage of owned subsidiaries										100.00%
Senior Notes, 1.25% Convertible Senior Notes due 2020, and Senior Subordinated Notes [Member
Debt Instrument [Line Items]
Aggregate principal amount exchanged			$ 964,000
Gain (loss) on extinguishment of debt							57,000
1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged			559,000	$ 129,000
Adjustment to equity component of 2020 Convertible Senior Notes upon extinguishment, net			63,000
Debt discount										$ 29,504	51,666				$ 238,000
Carrying value of debt instrument										562,075	562,075
6.5% Senior Subordinated Notes due 2018 [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged			26,000			$ 49,000
Gain (loss) on extinguishment of debt		$ (2,000)
Carrying value of debt instrument														$ 0
5.0% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged			42,000			97,000
Gain (loss) on extinguishment of debt	$ (31,000)
Carrying value of debt instrument											961,409		$ 0
5.75% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged			174,000			152,000
Carrying value of debt instrument										873,609	873,609
6.25% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Aggregate principal amount exchanged			$ 163,000			179,000
Carrying value of debt instrument										$ 408,296	$ 408,296
New Convertible Notes [Member]
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt								$ (188,000)
Fair value difference from principal amount						95,000
Debt discount						$ 185,000
Aggregate principal amount converted into shares								$ 477,000
Number of shares upon settlement of conversion								10.5
Carrying value of debt instrument								$ 0
Mandatory Convertible Notes [Member]
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt									$ (1,000)
Non cash charges									259,000
Fair value difference from principal amount					$ 69,000
Recognition of beneficial conversion features on convertible notes					233,000
Debt discount					$ 302,000		$ 302,000
Aggregate principal amount converted into shares									$ 1,093,000
Number of shares upon settlement of conversion									28.9
Carrying value of debt instrument									$ 0			$ 0

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations
Asset retirement obligations, current portion	$ 4,000	$ 5,000
Reconciliation of the Company's asset retirement obligations
Balance at the beginning of the period	134,237	177,004
Additional liability incurred	11,981	7,727
Revisions to estimated cash flows	(17,197)	(52,947)
Accretion expense	11,405	13,809
Obligations on sold properties	(676)	(6,988)
Liabilities settled	(3,916)	(4,368)
Balance at the end of the period	$ 135,834	$ 134,237

DERIVATIVE FINANCIAL INSTRUME_3

DERIVATIVE FINANCIAL INSTRUMENTS (Derivative instruments) (Details)	Feb. 27, 2019item	Dec. 31, 2018item$ / bbl
Crude Oil [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)		9,900,000
Collars [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)	900,000
Collars [Member] | Crude Oil [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)		9,900,000
Derivative, Floor Price (in dollars per Bbl) | $ / bbl		51.21
Derivative, Cap Price (in dollars per Bbl) | $ / bbl		77.14
Swap [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)	900,000

DERIVATIVE FINANCIAL INSTRUME_4

DERIVATIVE FINANCIAL INSTRUMENTS (Narrative) (Details)	Feb. 01, 2018USD ($)	Jul. 19, 2017USD ($)	Jul. 31, 2016USD ($)$ / bbl	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Mar. 31, 2016USD ($)
Derivative Financial Instruments [Line Items]
Payment to settle future minimum volume commitments				$ 61,036,000
New Convertible Notes [Member]
Derivative Financial Instruments [Line Items]
Fair value of embedded derivative liability							$ 90,000,000
Embedded derivatives [Member]
Derivative Financial Instruments [Line Items]
Fair value of embedded derivative liability						$ 0
Fair value of embedded derivative asset				$ 0	$ 0
Additional proceeds from disposal for specified period for each $0.01 average NYMEX futures is above threshold price per Bbl			$ 100,000
Incremental price per Bbl threshold for additional proceeds from sale | $ / bbl			0.01
Maximum possible additional proceeds from divestiture of business			$ 100,000,000
Amount received from settled contingent payment		$ 35,000,000
Embedded derivatives [Member] | North Ward Estes Properties [Member]
Derivative Financial Instruments [Line Items]
Average price per Bbl threshold for additional proceeds from sale | $ / bbl			50
Crude Oil Sales And Delivery Contract [Member]
Derivative Financial Instruments [Line Items]
Derivative liability	$ 0				$ 63,000,000
Payment to settle future minimum volume commitments	$ 61,000,000

DERIVATIVE FINANCIAL INSTRUME_5

DERIVATIVE FINANCIAL INSTRUMENTS (Effects of commodity derivative instruments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	$ 17,170	$ 122,847	$ (587)
Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	17,170	122,847
Commodity contracts [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income			58,771
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	$ 17,170	104,138
Embedded derivatives [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income			$ (59,358)
Embedded derivatives [Member] | Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income		$ 18,709

DERIVATIVE FINANCIAL INSTRUME_6

DERIVATIVE FINANCIAL INSTRUMENTS (Location and fair value of asset derivatives) (Details) - Not Designated as ASC 815 Hedges [Member] - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	$ 69,735	$ 9,829
Gross Amounts Offset	(1,393)	(9,829)
Total financial assets	68,342
Commodity contracts [Member] | Derivative Assets [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	69,735	9,829
Gross Amounts Offset	(1,393)	$ (9,829)
Total financial assets	$ 68,342

DERIVATIVE FINANCIAL INSTRUME_7

DERIVATIVE FINANCIAL INSTRUMENTS (Location and fair value of liability derivatives) (Details) - Not Designated as ASC 815 Hedges [Member] - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Gross amounts of derivative liabilities and gross amounts offset [Line Items]
Gross Amounts of Recognized Liabilities	$ 1,393	$ 142,354
Gross Amounts Offset	(1,393)	(9,829)
Total financial liabilities		132,525
Commodity contracts [Member] | Derivative Liabilities [Member]
Gross amounts of derivative liabilities and gross amounts offset [Line Items]
Gross Amounts of Recognized Liabilities	1,393	142,354
Gross Amounts Offset	$ (1,393)	(9,829)
Total financial liabilities		$ 132,525

FAIR VALUE MEASUREMENTS (Summar

FAIR VALUE MEASUREMENTS (Summary of the Fair values and carrying value of debt instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Mar. 31, 2015	Sep. 30, 2013
Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 2,601,722	$ 3,843,689
Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 2,792,321	3,723,429
5.0% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Interest Rate (as a percent)	5.00%			5.00%
5.0% Senior Notes due 2019 [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure		985,444
5.0% Senior Notes due 2019 [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure		958,713
1.25% Convertible Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure			$ 1,000,000
Interest Rate (as a percent)	1.25%		1.25%
1.25% Convertible Senior Notes due 2020 [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 531,161	517,109
1.25% Convertible Senior Notes due 2020 [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 530,231	506,231
5.75% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Interest Rate (as a percent)	5.75%
5.75% Senior Notes due 2021 [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 829,929	897,633
5.75% Senior Notes due 2021 [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 870,545	869,284
6.25% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Interest Rate (as a percent)	6.25%		6.25%
6.25% Senior Notes due 2023 [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 375,632	418,503
6.25% Senior Notes due 2023 [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 404,659	$ 403,940
6.625% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Interest Rate (as a percent)	6.625%	6.625%
6.625% Senior Notes due 2026 [Member] | Fair Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 865,000	$ 1,025,000
6.625% Senior Notes due 2026 [Member] | Carrying Value [Member]
Debt Instrument [Line Items]
Debt Instrument, Fair Value Disclosure	$ 986,886	$ 985,261

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, 2018	Dec. 31, 2017
Financial Assets
Total financial assets	$ 68,342
Financial Liabilities
Total financial liabilities		$ 132,525
Commodity contracts [Member]
Financial Assets
Financial assets - current	68,342
Financial Liabilities
Financial liabilities - current		132,525
Level 2 [Member]
Financial Assets
Total financial assets	68,342
Financial Liabilities
Total financial liabilities		69,247
Level 2 [Member] | Commodity contracts [Member]
Financial Assets
Financial assets - current	$ 68,342
Financial Liabilities
Financial liabilities - current		69,247
Level 3 [Member]
Financial Liabilities
Total financial liabilities		63,278
Level 3 [Member] | Commodity contracts [Member]
Financial Liabilities
Financial liabilities - current		$ 63,278

FAIR VALUE MEASUREMENTS (Narrat

FAIR VALUE MEASUREMENTS (Narrative) (Details) - USD ($) $ in Thousands	Feb. 01, 2018	Jul. 19, 2017	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Payment to settle future minimum volume commitments			$ 61,036
Embedded derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amount received from settled contingent payment		$ 35,000
Crude Oil Sales And Delivery Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Payment to settle future minimum volume commitments	$ 61,000

FAIR VALUE MEASUREMENTS (Reconc

FAIR VALUE MEASUREMENTS (Reconciliation-Level 3) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy
Fair value derivative, beginning of period		$ (63,278)	$ (9,214)
Unrealized gains (losses) on commodity derivative contracts included in earnings	[1]	2,242	(54,064)
Settlement of commodity derivative contracts		$ 61,036
Fair value derivative, end of period			$ (63,278)
[1]	Included in derivative (gain) loss, net in the consolidated statements of operations.

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		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
Nonrecurring [Member] | Proved Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property		389,390	[1]	$ 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)	Nov. 08, 2017shares	Nov. 30, 2017	Dec. 31, 2018shares	Dec. 31, 2017shares	Nov. 07, 2017shares
SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST [Abstract]
Reverse stock split ratio	0.25	0.25
Common stock, shares authorized	225,000,000		225,000,000	225,000,000	600,000,000

SHAREHOLDERS_ EQUITY AND NONC_3

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST (Schedule of noncontrolling interest) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2017
Noncontrolling Interest disclosures [Line Items]
Balance at beginning of period	$ 7,962
Net loss	(14)	$ (22)
Conveyance of ownership interest	$ (7,948)
Balance at end of period		$ 7,962
Sustainable Water Resources, LLC [Member]
Noncontrolling Interest disclosures [Line Items]
Third party ownership interest (as a percent)			25.00%

REVENUE RECOGNITION (Revenue Re

REVENUE RECOGNITION (Revenue Reclassification) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue, Practical Expedient, Initial Application and Transition, Nonrestatement of Modified Contract [true false]	true
Sales	$ 2,081,414	$ 1,481,435	$ 1,284,982
Gathering, transportation, compression and other	48,105	90,574	78,845
Total operating expenses	1,511,535	3,010,764	2,113,188
INCOME FROM OPERATIONS	569,879	$ (1,529,329)	$ (828,206)
Under ASC 605 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Sales	2,122,901
Gathering, transportation, compression and other	89,592
Total operating expenses	1,553,022
INCOME FROM OPERATIONS	569,879
Difference [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Sales	(41,487)
Gathering, transportation, compression and other	(41,487)
Total operating expenses	(41,487)
Oil sales [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Sales	1,850,052
Oil sales [Member] | Under ASC 605 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Sales	1,834,727
Oil sales [Member] | Difference [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Sales	15,325
NGL and natural gas sales [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Sales	231,362
NGL and natural gas sales [Member] | Under ASC 605 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Sales	288,174
NGL and natural gas sales [Member] | Difference [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Sales	$ (56,812)

REVENUE RECOGNITION (Narrative)

REVENUE RECOGNITION (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Jan. 01, 2018
Revenue Recognition [Line Items]
Receivable balance	$ 165	$ 186
Revenue, Practical Expedient, Initial Application and Transition, Nondisclosure of Transaction Price Allocation to Remaining Performance Obligation [true false]	true
Minimum [Member]
Revenue Recognition [Line Items]
Payment received for product sales, period	1 month
Maximum [Member]
Revenue Recognition [Line Items]
Payment received for product sales, period	3 months

STOCK-BASED COMPENSATION (Narra

STOCK-BASED COMPENSATION (Narrative) (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)item$ / sharesshares	Dec. 31, 2017USD ($)item$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2013shares
Share-based compensation disclosures [Line Items]
Number of shares authorized upon shareholder's approval				1,325,000
Number of additional shares authorized			1,375,000
Number of shares available for grant	1,043,446
Granted (in dollars per share) | $ / shares	$ 29.91
Unrecognized compensation cost, restricted stock | $	$ 13
Weighted average period over which cost will be recognized	1 year 8 months 12 days
Total fair value of restricted stock vested | $	$ 16	$ 15	$ 5
Stock compensation expense | $	$ 18	$ 22	$ 26
Scenario, Plan [Member]
Share-based compensation disclosures [Line Items]
Number of additional shares authorized	3,000,000
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
Stock options granted	0	0	0
Vesting (service) period	3 years
Unrecognized compensation cost, options | $	$ 0
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
Service-based [Member]
Share-based compensation disclosures [Line Items]
Granted (in shares)	249,983	538,194	737,912
Granted (in dollars per share) | $ / shares	$ 32.34	$ 40.66	$ 27.82
Service-based [Member] | Executive Officer And Employees [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	3 years
RSA [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	150,000
Maximum number of Shares per non-employee	25,000
RSA [Member] | Directors [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	1 year
RSU [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	150,000
Maximum number of Shares per non-employee	25,000
Granted (in shares)	308,432
Market-based [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	3 years
Granted (in shares)	230,932
Granted (in dollars per share) | $ / shares	$ 27.28	$ 63.04	$ 25.56
Target share granted percent, will be share-settled	100.00%
Market-based [Member] | Minimum [Member]
Share-based compensation disclosures [Line Items]
Possible multiplier of shares earned | item	0
Market-based [Member] | Maximum [Member]
Share-based compensation disclosures [Line Items]
Possible multiplier of shares earned | item	2
PSA [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	150,000
Vesting (service) period	3 years
Granted (in shares)		168,466	268,278
PSA [Member] | Minimum [Member]
Share-based compensation disclosures [Line Items]
Possible multiplier of shares earned | item		0
PSA [Member] | Maximum [Member]
Share-based compensation disclosures [Line Items]
Possible multiplier of shares earned | item		2
PSU [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	150,000

STOCK-BASED COMPENSATION (Assum

STOCK-BASED COMPENSATION (Assumptions) (Details) - Market-based [Member] - item	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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)	72.80%	82.44%	60.80%
Risk-free interest rate (as a percent)	2.12%	1.52%	1.13%
Dividend yield (as a percent)	0.00%	0.00%	0.00%

STOCK-BASED COMPENSATION (Summa

STOCK-BASED COMPENSATION (Summary of nonvested awards) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in dollars per share)	$ 45.55
Granted (in dollars per share)	29.91
Vested (in dollars per share)	41.98
Forfeited (in dollars per share)	60.59
Balance at the end of the period (in dollars per share)	$ 34.94	$ 45.55
Service-based [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in shares)	898,421
Granted (in shares)	249,983	538,194	737,912
Vested (in shares)	(461,982)
Forfeited (in shares)	(131,895)
Balance at the end of the period (in shares)	554,527	898,421
Granted (in dollars per share)	$ 32.34	$ 40.66	$ 27.82
Market-based [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in shares)	497,527
Granted (in shares)	230,932
Forfeited (in shares)	(224,763)
Balance at the end of the period (in shares)	503,696	497,527
Granted (in dollars per share)	$ 27.28	$ 63.04	$ 25.56

STOCK-BASED COMPENSATION (Sum_2

STOCK-BASED COMPENSATION (Summary of stock options) (Details) - Stock Option [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in shares)	122,034
Granted	0	0	0
Exercised (in shares)	(16,059)	0	0
Forfeited or expired (in shares)	(56,745)
Balance at the end of the period (in shares)	49,230	122,034
Options vested (in shares)	49,230
Options exercisable (in shares)	49,230
Balance at the beginning of the period (in dollars per share)	$ 154.32
Exercised (in dollars per share)	47.01
Forfeitures or expired (in dollars per share)	148.60
Balance at the end of the period (in dollars per share)	195.92	$ 154.32
Options vested (in dollars per share)	195.92
Options exercisable (in dollars per share)	$ 195.92
Aggregate Intrinsic Value, options Exercised	$ 129
Weighted Average Remaining Contractual Term, options outstanding	3 years 2 months 12 days
Weighted Average Remaining Contractual Term, options vested	3 years 2 months 12 days
Weighted Average Remaining Contractual Term, options exercisable	3 years 2 months 12 days

INCOME TAXES (Schedule of incom

INCOME TAXES (Schedule of income expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
INCOME TAXES [Abstract]
Federal		$ (7,305)	$ (7,340)
State		14	150
Total current income tax benefit		(7,291)	(7,190)
Federal	$ (10,960)	(398,686)	(65,130)
State	12,333	(77,002)	(15,326)
Total deferred income tax expense (benefit)	1,373	(475,688)	(80,456)
Total income tax expense (benefit)	$ 1,373	$ (482,979)	$ (87,646)

INCOME TAXES (Reconciliation of

INCOME TAXES (Reconciliation of statutory income tax expense to income expense) (Details) - USD ($) $ in Thousands	Jan. 01, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
U.S. statutory income tax rate (as a percent)	21.00%	21.00%	35.00%	35.00%
U.S. statutory income tax expense (benefit)		$ 72,211	$ (602,219)	$ (499,370)
State income taxes, net of federal benefit		14,324	(39,557)	(33,050)
Valuation allowance		(87,774)	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
Market-based equity awards		2,215	7,003	8,352
Other		397	4,553	(2,163)
Total income tax expense (benefit)		$ 1,373	(482,979)	(87,646)
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

INCOME TAXES (Components of def

INCOME TAXES (Components of deferred income tax assets and liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
INCOME TAXES [Abstract]
Net operating loss carryforward	$ 873,646	$ 828,617
Derivative instruments		31,567
Asset retirement obligations	32,546	16,138
Restricted stock compensation	5,603	9,704
EOR credit carryforwards	7,946	7,946
Other	10,777	11,549
Total deferred income tax assets	930,518	905,521
Less valuation allowances	(152,035)	(271,300)
Net deferred income tax assets	778,483	634,221
Oil and gas properties	740,933	566,747
Trust distributions	15,479	54,980
Derivative instruments	16,375
Discount on convertible senior notes	7,069	12,494
Total deferred income tax liabilities	779,856	$ 634,221
Total net deferred income tax liabilities	$ 1,373

INCOME TAXES (Narrative) (Detai

INCOME TAXES (Narrative) (Details) - USD ($)	Jan. 01, 2018	Sep. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
U.S. statutory income tax rate (as a percent)	21.00%		21.00%	35.00%	35.00%
Federal operating loss carryforwards			$ 3,100,000,000
Valuation allowance recognized		$ (41,000,000)	30,000,000		$ 259,000,000
EOR credit carryforwards			7,946,000	$ 7,946,000
Valuation allowance			$ 152,035,000	271,300,000
Tax Cut and Jobs Act of 2017, income tax expense, revaluation of deferred tax assets and liabilities				51,000,000
Tax Cut and Jobs Act of 2017, income tax benefit, reduction in existing valuation allowances				93,000,000
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					170,000
Unrecognized tax benefits, penalties and interest expense			0	0	0
Unrecognized tax benefits, penalties and interest accrued			0	0	$ 0
IRC Section 382 Limitations [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance			138,000,000	138,000,000
EOR Credits [Member]
Operating Loss Carryforwards [Line Items]
EOR credit carryforwards				8,000,000
Valuation allowance			8,000,000	8,000,000
Canadian NOL Carryforwards [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance			5,000,000	5,000,000
Short-Term Capital Loss Carryforwards [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance			$ 1,000,000	1,000,000
Valuation Allowance, Other [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance				$ 119,000,000

EARNINGS PER SHARE (Reconciliat

EARNINGS PER SHARE (Reconciliation) (Details) $ / shares in Units, shares in Thousands, $ in Thousands		Nov. 08, 2017	Nov. 30, 2017	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares
Basic Earnings (Loss) Per Share
Net income (loss) attributable to common shareholders, basic | $				$ 342,494	$ (1,237,648)	$ (1,339,102)
Weighted average shares outstanding, basic	[1]			90,953	90,683	62,967
Earnings (loss) per common share, basic (in dollars per share) | $ / shares	[1]			$ 3.77	$ (13.65)	$ (21.27)
Diluted Earnings (Loss) Per Share
Service-based awards, market-based awards and stock options				916
Weighted average shares outstanding, diluted	[1]			91,869	90,683	62,967
Earnings (loss) per common share, diluted (in dollars per share) | $ / shares	[1]			$ 3.73	$ (13.65)	$ (21.27)
Reverse stock split ratio		0.25	0.25
[1]	All share and per share amounts have been retroactively adjusted for the 2016 period to reflect the Company’s one-for-four reverse stock split in November 2017, as described in Note 8 to these consolidated financial statements.

EARNINGS PER SHARE (Narrative)

EARNINGS PER SHARE (Narrative) (Details) item in Millions	12 Months Ended
	Dec. 31, 2018shares	Dec. 31, 2017itemshares	Dec. 31, 2016shares
Stock Option [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Antidilutive securities excluded from computation of earnings per share		1,083	1,158
Stock options excluded from earnings per share calculation (in shares)	100,708	123,775	136,291
Service-based [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Antidilutive securities excluded from computation of earnings per share		509,744	444,646
Market-based [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Antidilutive securities excluded from computation of earnings per share		22,946
Market-based awards excluded from earnings per share calculation (in shares)		345,071	469,545
1.25% Convertible Senior Notes due 2020 [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Antidilutive securities excluded from computation of earnings per share			10,820,758
Debt instrument, convertible, number of common stock | item		3.6

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Minimum future payments) (Details) $ in Thousands	Dec. 31, 2018USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
2,019	$ 46,549
2,020	13,561
2,021	11,113
2,022	10,045
2,023	9,421
Thereafter	31,251
Total	121,940
Real Estate Leases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,019	7,407
2,020	4,770
2,021	4,066
2,022	4,188
2,023	4,017
Thereafter	25,140
Total	49,588
Pipeline Transportation Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,019	5,369
2,020	5,369
2,021	5,369
2,022	5,369
2,023	5,369
Thereafter	6,111
Total	32,956
Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,019	29,557
Total	29,557
Automobile and Equipment Leases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,019	4,216
2,020	3,422
2,021	1,678
2,022	488
2,023	35
Total	$ 9,839

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES (Unconditional obligations) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)ft²contract	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Total fixed obligation	$ 121,940
Real Estate Leases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Rental expense	8,000	$ 8,000	$ 9,000
Total fixed obligation	$ 49,588
Real Estate Leases [Member] | Denver Colorado, Lease Expiring October 2019 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²	222,900
Real Estate Leases [Member] | Denver Colorado, Lease Commencing by November 2019 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²	135,175
Real Estate Leases [Member] | Dickinson, North Dakota [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²	81,875
Real Estate Leases [Member] | Midland, Texas [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet) | ft²	44,500
Pipeline Transportation Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total fixed obligation	$ 32,956
Payments under purchase contracts	$ 5,000	7,000	5,000
Pipeline Transportation Agreements, Total [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts | contract	3
Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts | contract	5
Total fixed obligation	$ 29,557
Payments under purchase contracts	33,000	29,000	31,000
Termination penalties	22,000
Automobile and Equipment Leases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Rental expense	5,000	$ 5,000	$ 7,000
Total fixed obligation	$ 9,839

COMMITMENTS AND CONTINGENCIES_4

COMMITMENTS AND CONTINGENCIES (Other than unconditional obligations) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)bblcontractitem	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Pipeline Transportation Agreements [Member]
Commitments
Future estimated commitments	$ 13
Take-Or-Pay Agreements [Member]
Commitments
Future estimated commitments	16
Payments under purchase contracts	8	$ 22	$ 1
Deficiency payments	2
Water Disposal Agreement [Member]
Commitments
Future estimated commitments		103
Payments under purchase contracts	19	16	8
Deficiency payments	$ 5	4	2
Crude Oil Sales And Delivery Contract [Member]
Commitments
Number of contracts | contract	2
Crude Oil Sales And Delivery Contract [Member] | Mountrail County, North Dakota [Member]
Commitments
Number of contracts | item	1
Delivery commitments, volume per day | bbl	15,000
Delivery commitment term	7 years
Crude Oil Sales And Delivery Contract [Member] | Weld County, Colorado [Member]
Commitments
Deficiency payments	$ 39	$ 66	$ 43
Delivery commitments for 2019 | bbl	16,000
Delivery commitments for year 2020 | bbl	4,100

CAPITALIZED EXPLORATORY WELL _3

CAPITALIZED EXPLORATORY WELL COSTS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
CAPITALIZED EXPLORATORY WELL COSTS [Abstract]
Balance at the beginning of the period	$ 13,894
Additions to capitalized exploratory well costs pending the determination of proved reserves	10,831	$ 13,894
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(24,725)
Balance at the end of the period		$ 13,894
Capitalized exploratory cost for exploratory wells in progress	$ 0