Chord Energy (WLLBW) 10-K 28 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 14, 2014	Jun. 30, 2013
Document and Entity Information	'	'	'
Entity Registrant Name	'WHITING PETROLEUM CORP	'	'
Entity Central Index Key	'0001255474	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Public Float	'	'	$5,481,981,242
Entity Common Stock, Shares Outstanding	'	118,956,489	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$699,460	$44,800
Accounts receivable trade, net	341,177	318,265
Prepaid expenses and other	28,981	21,347
Total current assets	1,069,618	384,412
Property and equipment:	'	'
Oil and gas properties, successful efforts method	10,065,150	9,211,998
Other property and equipment	206,385	141,738
Total property and equipment	10,271,535	9,353,736
Less accumulated depreciation, depletion and amortization	-2,676,490	-2,590,203
Total property and equipment, net	7,595,045	6,763,533
Debt issuance costs	48,530	28,748
Other long-term assets	120,277	95,726
TOTAL ASSETS	8,833,470	7,272,419
Current liabilities:	'	'
Accounts payable trade	107,692	131,370
Accrued capital expenditures	158,739	110,663
Accrued liabilities and other	214,109	170,207
Revenues and royalties payable	198,558	149,692
Taxes payable	50,052	33,283
Accrued interest	44,405	10,415
Derivative liabilities	3,482	21,955
Deferred income taxes	648	9,394
Total current liabilities	777,685	636,979
Long-term debt	2,653,834	1,800,000
Deferred income taxes	1,278,030	1,063,681
Derivative liabilities	'	1,678
Production Participation Plan liability	87,503	94,483
Asset retirement obligations	116,442	86,179
Deferred gain on sale	79,065	110,395
Other long-term liabilities	4,212	25,852
Total liabilities	4,996,771	3,819,247
Commitments and contingencies	'	'
Equity:	'	'
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible perpetual preferred stock, no shares authorized, issued or outstanding as of December 31, 2013 and 172,391 shares issued and outstanding as of December 31, 2012	'	'
Common stock, $0.001 par value, 300,000,000 shares authorized; 120,101,555 issued and 118,657,245 outstanding as of December 31, 2013 and 118,582,477 issued and 117,631,451 outstanding as of December 31, 2012	120	119
Additional paid-in capital	1,583,542	1,566,717
Accumulated other comprehensive loss	'	-1,236
Retained earnings	2,244,905	1,879,388
Total Whiting shareholders' equity	3,828,567	3,444,988
Noncontrolling interest	8,132	8,184
Total equity	3,836,699	3,453,172
TOTAL LIABILITIES AND EQUITY	$8,833,470	$7,272,419

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013
Common stock, par value (in dollars per share)	$0.00	0.001
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares issued	118,582,477	120,101,555
Common stock, shares outstanding	117,631,451	118,657,245
Preferred Stock	'	'
Preferred stock, par value (in dollars per share)	$0.00	0.001
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	'	0
Preferred stock, shares outstanding	'	0
Convertible perpetual preferred stock	'	'
Preferred stock, par value (in dollars per share)	$0.00	'
Preferred stock, shares authorized	5,000,000	0
Preferred stock, shares issued	172,391	0
Preferred stock, shares outstanding	172,391	0
Convertible perpetual preferred stock (as a percent)	6.25%	'

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES AND OTHER INCOME:	'	'	'
Oil, NGL and natural gas sales	$2,666,549	$2,137,714	$1,860,146
Gain (loss) on hedging activities	-1,958	2,338	8,758
Amortization of deferred gain on sale	31,737	29,458	13,937
Gain on sale of properties	128,648	3,423	16,313
Interest income and other	3,409	519	468
Total revenues and other income	2,828,385	2,173,452	1,899,622
COSTS AND EXPENSES:	'	'	'
Lease operating	430,221	376,424	305,487
Production taxes	225,403	171,625	139,190
Depreciation, depletion and amortization	891,516	684,724	468,203
Exploration and impairment	453,210	166,972	84,644
General and administrative	137,994	108,573	84,985
Interest expense	112,936	75,210	62,516
Loss on early extinguishment of debt	4,412	'	'
Change in Production Participation Plan liability	-6,980	13,824	-865
Commodity derivative (gain) loss, net	7,802	-85,911	-24,857
Total costs and expenses	2,256,514	1,511,441	1,119,303
INCOME BEFORE INCOME TAXES	571,871	662,011	780,319
INCOME TAX EXPENSE (BENEFIT):	'	'	'
Current	986	-669	3,853
Deferred	204,882	248,581	284,838
Total income tax expense	205,868	247,912	288,691
NET INCOME	366,003	414,099	491,628
Net loss attributable to noncontrolling interest	52	90	59
NET INCOME AVAILABLE TO SHAREHOLDERS	366,055	414,189	491,687
Preferred stock dividends	-538	-1,077	-1,077
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$365,517	$413,112	$490,610
EARNINGS PER COMMON SHARE:	'	'	'
Basic (in dollars per share)	$3.09	$3.51	$4.18
Diluted (in dollars per share)	$3.06	$3.48	$4.14
WEIGHTED AVERAGE SHARES OUTSTANDING:	'	'	'
Basic (in shares)	118,260	117,601	117,345
Diluted (in shares)	119,588	119,028	118,668

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	'		'		'
NET INCOME	$366,003		$414,099		$491,628
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:	'		'		'
OCI amortization on de-designated hedges	1,236	[1],[2]	-1,476	[1],[2]	-5,528	[1],[2]
Total other comprehensive income (loss), net of tax	1,236		-1,476		-5,528
COMPREHENSIVE INCOME	367,239		412,623		486,100
Comprehensive loss attributable to noncontrolling interest	52		90		59
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING	$367,291		$412,713		$486,159
[1]	Presented net of income tax expense of $722 for the year ended December 31, 2013 and income tax benefits of $862 and $3,230 for the years ended December 31, 2012 and 2011, respectively.
[2]	These gain (loss) amounts on de-designated hedges are reclassified from accumulated other comprehensive income ("AOCI") to gain (loss) on hedging activities in the consolidated statements of income.

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME	'	'	'
OCI amortization on de-designated hedges, income tax expense (benefits)	$722	($862)	($3,230)

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012
				Other property	Other property	Other property	Whiting USA Trust II Units
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'	'	'	'	'	'
Net income (loss)	$366,003	$414,099	$491,628	'	'	'	'
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'	'	'	'	'
Depreciation, depletion and amortization	891,516	684,724	468,203	'	'	'	'
Deferred income tax expense	204,882	248,581	284,838	'	'	'	'
Amortization of debt issuance costs and debt premium	12,405	9,518	8,682	'	'	'	'
Stock-based compensation	22,436	18,190	13,509	'	'	'	'
Amortization of deferred gain on sale	-31,737	-29,458	-13,937	'	'	'	'
Gain on sale of properties	-128,648	-3,423	-16,313	'	'	'	'
Undeveloped leasehold and oil and gas property impairments	358,455	107,855	38,783	'	'	'	'
Exploratory dry hole costs	28,725	18,428	4,924	'	'	'	'
Loss on early extinguishment of debt	4,412	'	'	'	'	'	'
Change in Production Participation Plan liability	-6,980	13,824	-865	'	'	'	'
Non-cash portion of derivative (gains) and losses	-20,830	-115,733	-63,093	'	'	'	'
Other, net	-16,118	-18,708	-13,512	'	'	'	'
Changes in current assets and liabilities:	'	'	'	'	'	'	'
Accounts receivable trade	-22,912	-55,750	-62,802	'	'	'	'
Prepaid expenses and other	-15,981	2,535	-3,771	'	'	'	'
Accounts payable trade and accrued liabilities	33,360	58,647	33,135	'	'	'	'
Revenues and royalties payable	48,988	45,798	21,770	'	'	'	'
Taxes payable	16,769	2,088	904	'	'	'	'
Net cash provided by operating activities	1,744,745	1,401,215	1,192,083	'	'	'	'
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'	'	'	'	'
Drilling and development capital expenditures	-2,349,819	-2,050,029	-1,554,271	'	'	'	'
Acquisition of oil and gas properties	-422,923	-125,282	-193,809	'	'	'	'
Other property and equipment	-45,304	3,852	-56,232	'	'	'	'
Proceeds from sale of oil and gas properties	'	'	'	968,606	69,190	69,276	322,257
Issuance of note receivable	-10,530	-306	-25,000	'	'	'	'
Cash paid for investing derivatives	-44,900	'	'	'	'	'	'
Cash settlements received on investing derivatives	2,371	'	'	'	'	'	'
Net cash used in investing activities	-1,902,499	-1,780,318	-1,760,036	'	'	'	'
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'	'	'	'	'
Long-term borrowings under credit agreement	1,860,000	2,340,000	1,760,000	'	'	'	'
Repayments of long-term borrowings under credit agreement	-3,060,000	-1,920,000	-1,180,000	'	'	'	'
Debt issuance costs	-29,690	-2,807	-5,691	'	'	'	'
Restricted stock used for tax withholdings	-5,611	-5,695	-9,049	'	'	'	'
Repayments to Alliant Energy Corporation	-1,759	-2,329	-1,871	'	'	'	'
Preferred stock dividends paid	-538	-1,077	-1,077	'	'	'	'
Contributions from noncontrolling interest	'	'	2,500	'	'	'	'
Net cash provided by financing activities	812,414	408,092	564,812	'	'	'	'
NET CHANGE IN CASH AND CASH EQUIVALENTS	654,660	28,989	-3,141	'	'	'	'
CASH AND CASH EQUIVALENTS:	'	'	'	'	'	'	'
Beginning of period	44,800	15,811	18,952	'	'	'	'
End of period	699,460	44,800	15,811	'	'	'	'
SUPPLEMENTAL CASH FLOW DISCLOSURES:	'	'	'	'	'	'	'
Income taxes paid (refunded), net	3,681	-268	4,065	'	'	'	'
Interest paid, net of amounts capitalized	66,541	68,005	53,761	'	'	'	'
NONCASH INVESTING ACTIVITIES:	'	'	'	'	'	'	'
Accrued capital expenditures	158,739	110,663	142,827	'	'	'	'
NONCASH FINANCING ACTIVITIES:	'	'	'	'	'	'	'
Contributions from noncontrolling interest	'	'	$5,833	'	'	'	'

CONSOLIDATED_STATEMENTS_OF_CAS1

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2013	Sep. 26, 2013	Dec. 31, 2013
		5% Senior Notes due 2019	5% Senior Notes due 2019	5.75% Senior Notes due 2021	5.75% Senior Notes due 2021	5.75% Senior Notes due 2021	7% Senior Subordinated Notes due 2014
CONSOLIDATED STATEMENTS OF CASH FLOWS	'	'	'	'	'	'	'
Trust units sold to the public (in shares)	18,400,000	'	'	'	'	'	'
Statement	'	'	'	'	'	'	'
Interest rate on debt instrument (as a percent)	'	5.00%	5.00%	5.75%	5.75%	5.75%	7.00%

CONSOLIDATED_STATEMENTS_OF_EQU

CONSOLIDATED STATEMENTS OF EQUITY (USD $)	Total	Total Whiting Shareholders' Equity	Preferred Stock	Common Stock	Additional Paid-in Capital	Accumulated Other Comprehensive Income (Loss)	Retained Earnings	Noncontrolling Interest
In Thousands, except Share data, unless otherwise specified	USD ($)	USD ($)		USD ($)	USD ($)	USD ($)	USD ($)	USD ($)
BALANCES at Dec. 31, 2010	$2,531,315	$2,531,315	'	$59	$1,549,822	$5,768	$975,666	'
BALANCES (in shares) at Dec. 31, 2010	'	'	173,000	117,968,000	'	'	'	'
Increase (Decrease) in Shareholders' Equity	'	'	'	'	'	'	'	'
Net income (loss)	491,628	491,687	'	'	'	'	491,687	-59
Other comprehensive loss (income)	-5,528	-5,528	'	'	'	-5,528	'	'
Conversion of preferred stock to common (in shares)	'	'	-1,000	1,000	'	'	'	'
Two-for-one stock split	'	'	'	59	-59	'	'	'
Contributions from noncontrolling interest	8,333	'	'	'	'	'	'	8,333
Restricted stock issued (in shares)	'	'	'	304,000	'	'	'	'
Restricted stock forfeited (in shares)	'	'	'	-20,000	'	'	'	'
Restricted stock used for tax withholdings	-9,049	-9,049	'	'	-9,049	'	'	'
Restricted stock used for tax withholdings (in shares)	'	'	'	-148,000	'	'	'	'
Stock-based compensation	13,509	13,509	'	'	13,509	'	'	'
Preferred dividends paid	-1,077	-1,077	'	'	'	'	-1,077	'
BALANCES at Dec. 31, 2011	3,029,131	3,020,857	'	118	1,554,223	240	1,466,276	8,274
BALANCES (in shares) at Dec. 31, 2011	'	'	172,000	118,105,000	'	'	'	'
Increase (Decrease) in Shareholders' Equity	'	'	'	'	'	'	'	'
Net income (loss)	414,099	414,189	'	'	'	'	414,189	-90
Other comprehensive loss (income)	-1,476	-1,476	'	'	'	-1,476	'	'
Restricted stock issued	'	'	'	1	-1	'	'	'
Restricted stock issued (in shares)	'	'	'	592,000	'	'	'	'
Restricted stock forfeited (in shares)	'	'	'	-9,000	'	'	'	'
Restricted stock used for tax withholdings	-5,695	-5,695	'	'	-5,695	'	'	'
Restricted stock used for tax withholdings (in shares)	'	'	'	-106,000	'	'	'	'
Stock-based compensation	18,190	18,190	'	'	18,190	'	'	'
Preferred dividends paid	-1,077	-1,077	'	'	'	'	-1,077	'
BALANCES at Dec. 31, 2012	3,453,172	3,444,988	'	119	1,566,717	-1,236	1,879,388	8,184
BALANCES (in shares) at Dec. 31, 2012	'	'	172,000	118,582,000	'	'	'	'
Increase (Decrease) in Shareholders' Equity	'	'	'	'	'	'	'	'
Net income (loss)	366,003	366,055	'	'	'	'	366,055	-52
Other comprehensive loss (income)	1,236	1,236	'	'	'	1,236	'	'
Conversion of preferred stock to common	1	1	'	1	'	'	'	'
Conversion of preferred stock to common (in shares)	'	'	-172,000	794,000	'	'	'	'
Restricted stock issued (in shares)	'	'	'	941,000	'	'	'	'
Restricted stock forfeited (in shares)	'	'	'	-100,000	'	'	'	'
Restricted stock used for tax withholdings	-5,611	-5,611	'	'	-5,611	'	'	'
Restricted stock used for tax withholdings (in shares)	'	'	'	-115,000	'	'	'	'
Stock-based compensation	22,436	22,436	'	'	22,436	'	'	'
Preferred dividends paid	-538	-538	'	'	'	'	-538	'
BALANCES at Dec. 31, 2013	$3,836,699	$3,828,567	'	$120	$1,583,542	'	$2,244,905	$8,132
BALANCES (in shares) at Dec. 31, 2013	'	'	'	120,102,000	'	'	'	'

CONSOLIDATED_STATEMENTS_OF_EQU1

CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical)	12 Months Ended
	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF EQUITY	'
Stock split ratio	2

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2013
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
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 that explores for, develops, acquires and produces crude oil, NGLs and natural gas primarily in the Rocky Mountains and Permian Basin regions of the United States.  Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries.
	Basis of Presentation of Consolidated Financial Statements—The consolidated financial statements include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s 15.8% ownership interest in Trust I.  Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method.  Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses.  All intercompany balances and transactions have been eliminated upon consolidation.
	Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  Items subject to such estimates and assumptions include (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) Production Participation Plan and other accrued liabilities; (8) valuation of derivative instruments; and (9) accrued revenue and related receivables.  Although management believes these estimates are reasonable, actual results could differ from these estimates.
	Cash and Cash Equivalents—Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.
	Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates.  For receivables from joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.  Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts.
	The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability.  At December 31, 2013 and 2012, the Company had an allowance for doubtful accounts of $4.2 million and $3.9 million, respectively.
	Inventories—Materials and supplies inventories consist primarily of tubular goods and production equipment, carried at weighted-average cost.  Materials and supplies are included in other property and equipment.  Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or market value and is included in prepaid expenses and other.
	Oil and Gas Properties
	Proved.  The Company follows the successful efforts method of accounting for its oil and gas properties.  Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.  Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.
	The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable.  The impairment test compares undiscounted future net cash flows to the assets’ net book value.  If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value.  Fair value for oil and gas properties is generally determined based on discounted future net cash flows.  Impairment expense for proved properties is reported in exploration and impairment expense.
	Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income.  Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.
	Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use.  During 2013, 2012 and 2011, the Company capitalized interest of $1.5 million, $2.7 million and $3.6 million, respectively.
	Unproved.  Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves.  Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on past success, past experience and average lease-term lives.  The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.  When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis.  Impairment expense for unproved properties is reported in exploration and impairment expense.
	Exploratory.  Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred.  Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs.  Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations.  To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
	Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves.  If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense.  Cost incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.  If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.
	Enhanced recovery activities.  The Company carries out tertiary recovery methods on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods.  Acquisition costs of tertiary injectants, such as purchased CO2, for enhanced oil recovery (“EOR”) activities that are used during a project’s pilot phase, or prior to a project’s technical and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as incurred.  After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project.  As CO2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO2 recycling costs are expensed as incurred.  Likewise costs incurred to maintain reservoir pressure are also expensed.
	Other Property and Equipment—Other property and equipment consists of (i) materials and supplies inventories, (ii) leasehold costs and development costs of our CO2 source properties and (iii) other property and equipment including an oil pipeline, 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 33 years.  In July 2013, the Company sold the oil pipeline, as discussed in the Acquisitions and Divestitures footnote.
	Debt Issuance Costs—Debt issuance costs related to the Company’s Senior Notes and Senior Subordinated Notes 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 amortized to interest expense on a straight-line basis over the borrowing term.
	Asset Retirement Obligations and Environmental Costs—Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or 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 units-of-production basis over the proved developed reserves of the related asset.  Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability.
	Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that obligations have been incurred and the amounts can be reasonably estimated.  These liabilities are not reduced by possible recoveries from third parties.
	Derivative Instruments—The Company enters into derivative contracts, primarily costless collars, to manage its exposure to commodity price risk.  All derivative instruments, other than those that meet the “normal purchase normal sales” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value.  Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria, and the derivative has been designated as a hedge.  Effective April 1, 2009, however, the Company elected to discontinue all hedge accounting prospectively.  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.
	For derivatives qualifying as hedges of future cash flows prior to April 1, 2009, the effective portion of any changes in fair value was recognized in accumulated other comprehensive income (loss) and was reclassified to net income when the underlying forecasted transaction occurred.  Any ineffective portion of such hedges was recognized in commodity derivative (gain) loss, net as it occurred.  For discontinued cash flow hedges, prospective changes in the fair value of the derivative are recognized in earnings.  The accumulated gain or loss recognized in accumulated other comprehensive income (loss) at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs.  However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in accumulated other comprehensive income (loss) is immediately reclassified into earnings.  As of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings.
	Deferred Gain on Sale—The deferred gain on sale relates to the sale of 11,677,500 Trust I units and 18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the units-of-production method.
	Revenue Recognition—Oil and gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, persuasive evidence of a sales arrangement exists and collectability of the revenue is probable.  Revenues from the production of gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest (entitlement method).  Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as receivables.  Gas imbalance receivables or payables are valued at the lowest of (i) the current market price, (ii) the price in effect at the time of production, or (iii) the contract price, if a contract is in hand.  As of December 31, 2013 and 2012, the Company was in a net under (over) produced imbalance position of (110,798) Mcf and (53,536) Mcf, respectively.
	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 working interest owners in the oil and gas properties operated by Whiting.
	Acquisition Costs—Acquisition related expenses, which consist of external costs directly related to the Company’s acquisitions, such as advisory, legal, accounting, valuation and other professional fees are expensed as incurred.
	Maintenance and Repairs—Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred.  Major replacements, renewals and betterments are capitalized.
	Income Taxes—Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes.  Deferred income taxes are accounted for using the liability method.  Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.  The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense.
	Earnings Per Share—Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period.  Diluted earnings per common share is calculated by dividing adjusted net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options using the treasury method, as well as convertible perpetual preferred stock using the if-converted method.  In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized.  When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.
	Industry Segment and Geographic Information—The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, NGLs and natural gas.  The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities.  All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.
	Fair Value of Financial Instruments—The Company has included fair value information in these notes when the fair value of our financial instruments is materially different from their book value.  Cash and cash equivalents, accounts receivable and payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments.  The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates.  The Company’s Senior Notes and Senior Subordinated Notes are recorded at cost, and the fair values of these instruments are included in the Long-Term Debt footnote.  The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate.
	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 table presents the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2013, 2012 and 2011:
		2013		2012		2011
	Plains Marketing LP	21	%	20	%	27	%
	Shell Trading US	14	%	14	%	13	%
	Eighty Eight Oil Company	11	%	11	%	8	%
	Bridger Trading LLC	8	%	11	%	6	%
	Commodity derivative contracts held by the Company are with eight counterparties, all of which are participants in Whiting’s credit facility as well, and all of which have investment-grade ratings from Moody’s and Standard & Poor.  As of December 31, 2013, outstanding derivative contracts with JP Morgan Chase Bank, N.A., Canadian Imperial Bank of Commerce, The Bank of Nova Scotia and Bank of America Merrill Lynch represented 29%, 21%, 12% and 12%, respectively, of total crude oil volumes hedged.
	Reclassifications—Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current year presentation.  Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
	Adopted and Recently IssuedAccounting Pronouncements—In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which provides amendments to FASB ASC Topic 820, Fair Value Measurement.  The objective of ASU 2011-04 is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”).  The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements.  ASU 2011-04 was effective for interim and annual reporting periods beginning after December 15, 2011.  The Company adopted this standard effective January 1, 2012, which did not have an impact on the Company’s consolidated financial statements other than additional disclosures.
	In June 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income: Presentation of Comprehensive Income (“ASU 2011-05”), which provides amendments to FASB ASC Topic 220, Comprehensive Income.  The objective of ASU 2011-05 is to require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements.  ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of equity.  ASU 2011-05 is effective for interim and annual periods beginning after December 15, 2011 and is to be applied retrospectively.  In December 2011, the FASB issued Accounting Standards Update No. 2011-12, Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which deferred the effective date of changes in ASU 2011-05 that relate to the presentation of reclassification adjustments out of accumulated other comprehensive income.  The amendments in this update are effective at the same time as the amendments in ASU 2011-05.  The Company adopted the provisions of ASU 2011-05 and 2011-12 effective January 1, 2012, which did not have an impact on its consolidated financial statements other than requiring the Company to present its statements of comprehensive income separately from its statements of equity, as these statements were formerly presented on a combined basis.
	In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”).  The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position.  In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with FASB ASC Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities lending transactions that are either offset in accordance with FASB ASC Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement.  ASU 2011-11 and ASU 2013-01 are effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively.  The Company adopted ASU 2011-11 and ASU 2013-01 effective January 1, 2013, which did not have an impact on the Company’s consolidated financial statements other than additional disclosures.
	In July 2012, the FASB issued Accounting Standards Update No. 2012-02, Intangibles — Goodwill and Other — Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”).  The objective of ASU 2012-02 is to reduce the cost and complexity of performing an impairment test for indefinite-lived intangible assets by permitting an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired, as a basis for determining whether it is necessary to perform a quantitative impairment test.  ASU 2012-02 is effective for interim and annual reporting periods beginning after September 15, 2012.  The Company adopted ASU 2012-02 effective January 1, 2013, which did not have an impact on the Company’s consolidated financial statements.
	In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”).  The objective of ASU 2013-02 is to improve the reporting of reclassifications out of AOCI by requiring an entity to report the effect of significant reclassifications out of AOCI on the respective line items in net income if the amount being reclassified is required under GAAP to be reclassified in its entirety to net income.  For other amounts that are not required under GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under GAAP that provide additional detail about those amounts.  ASU 2013-02 is effective for interim and annual reporting periods beginning after December 15, 2012.  The Company adopted ASU 2013-02 effective January 1, 2013, which did not have a significant impact on the Company’s consolidated financial statements.
	In February 2013, the FASB issued Accounting Standards Update No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“ASU 2013-04”).  The objective of ASU 2013-04 is to provide guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date.  ASU 2013-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.  The adoption of this standard will not have an impact on the Company’s consolidated financial statements.
	In July 2013, the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”).  The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists.  ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.  The adoption of this standard will not have an impact on the Company’s consolidated financial statements, other than insignificant balance sheet reclassifications.

OIL_AND_GAS_PROPERTIES

OIL AND GAS PROPERTIES	12 Months Ended
	Dec. 31, 2013
OIL AND GAS PROPERTIES	'
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, 2013 and 2012 are as follows (in thousands):
		December 31,
		2013			2012
	Proved leasehold costs	$	1,633,495		$	2,119,541
	Unproved leasehold costs	372,298			362,483
	Costs of completed wells and facilities	7,563,350			6,369,170
	Wells and facilities in progress	496,007			360,804
	Total oil and gas properties, successful efforts method	10,065,150			9,211,998
	Accumulated depletion	(2,645,841		)	(2,564,081		)
	Oil and gas properties, net	$	7,419,309		$	6,647,917

ACQUISITIONS_AND_DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2013
ACQUISITIONS AND DIVESTITURES	'
ACQUISITIONS AND DIVESTITURES	'
	3.                                      ACQUISITIONS AND DIVESTITURES
	2013 Acquisitions
	On September 20, 2013, the Company completed the acquisition of approximately 39,300 gross (17,300 net) acres, including interests in 121 producing oil and gas wells and undeveloped acreage, in the Williston Basin located in Williams and McKenzie counties of North Dakota and Roosevelt and Richland counties of Montana for an aggregate unadjusted purchase price of $260.0 million.  Revenue and earnings from these properties since the September 20, 2013 acquisition date, which are included in the consolidated statements of income for the year ended December 31, 2013, are not material.  Disclosures of pro forma revenues and net income for the acquisition of these wells are not material and have not been presented accordingly.
	The acquisition was recorded using the purchase method of accounting.  The following table summarizes the preliminary allocation of the $258.9 million adjusted purchase price (which is still subject to post-closing adjustments) to the tangible assets acquired and liabilities assumed in this acquisition oil and gas properties.  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):
	Purchase price	$	258,892
	Allocation of purchase price:
	Proved properties	$	232,187
	Unproved properties	27,335
	Oil in tank inventory	692
	Accounts receivable	578
	Asset retirement obligations	(1,900		)
	Total	$	258,892
	2013 Divestitures
	On October 31, 2013, the Company completed the sale of approximately 45,000 gross (32,200 net) acres, including its interests in certain producing oil and gas wells and undeveloped acreage, in its Big Tex prospect located in the Delaware Basin for a cash purchase price of $152.0 million (subject to post-closing adjustments), resulting in a pre-tax gain on sale of $13.0 million.  Of the total net acres sold, approximately 30,800 net acres are located in Pecos County, Texas, and approximately 1,400 net acres are located in Reeves County, Texas.
	On July 15, 2013, the Company completed the sale of its interests in certain oil and gas producing properties located in its enhanced oil recovery projects in the Postle and Northeast Hardesty fields in Texas County, Oklahoma, including the related Dry Trail plant gathering and processing facility, oil delivery pipeline, its entire 60% interest in the Transpetco CO2 pipeline, crude oil swap contracts and certain other related assets and liabilities (collectively the “Postle Properties”) for a cash purchase price of $809.7 million after selling costs and post-closing adjustments, resulting in a pre-tax gain on sale of $109.7 million.  The Company used the net proceeds from this sale to repay a portion of the debt outstanding under its credit agreement.
	Upon closing of the transaction, the following crude oil swaps and any of their related cash settlements as of that date were transferred to the buyer of the Postle Properties:
	Period	Contracted Crude Oil Volumes		NYMEX Price for Crude Oil
		(Bbl)		(per Bbl)
	Apr – Dec 2013	1,677,500		$	98.5
	Jan – Dec 2014	2,007,500		$	94.75
	Jan – Dec 2015	1,825,000		$	94.75
	Jan – Mar 2016	400,400		$	93.5
	Total	5,910,400
	2012 Acquisitions
	On March 22, 2012, the Company completed the acquisition of approximately 13,300 net undeveloped acres in the Missouri Breaks field in Richland County, Montana for $33.3 million.
	2012 Divestitures
	On May 18, 2012, the Company sold a 50% ownership interest in its Belfield gas processing plant, natural gas gathering system, oil gathering system and related facilities located in Stark County, North Dakota for total cash proceeds of $66.2 million.  Whiting used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement.
	On March 28, 2012, the Company completed an initial public offering of units of beneficial interest in Trust II, selling 18,400,000 Trust II units at $20.00 per unit, which generated net proceeds of $322.3 million after underwriters’ fees, offering expenses and post-close adjustments.  The Company used the net offering proceeds to repay a portion of the debt outstanding under its credit agreement.  The net proceeds from the sale of Trust II units to the public resulted in a deferred gain on sale of $128.2 million.  Immediately prior to the closing of the offering, Whiting conveyed a term net profits interest in certain of its oil and gas properties to Trust II in exchange for 100% of the trust’s units issued, or 18,400,000 units.
	The net profits interest entitles Trust II to receive 90% of the net proceeds from the sale of oil and natural gas production from the underlying properties.  The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold.  This is the equivalent of 10.61 MMBOE in respect of Trust II’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest.
	2011 Acquisitions
	On July 28, 2011, the Company completed the acquisition of approximately 23,400 net acres and one well in the Missouri Breaks field in Richland County, Montana for an unadjusted purchase price of $46.9 million.  Disclosures of pro forma revenues and net income for the acquisition of this one well are not material and have not been presented accordingly.
	On March 18, 2011, Whiting and an unrelated third party formed Sustainable Water Resources, LLC (“SWR”) to develop a water project in the state of Colorado.  The Company contributed $25.0 million for a 75% interest in SWR, and the 25% noncontrolling interest in SWR was ascribed a fair value of $8.3 million, which consisted of $2.5 million in cash contributions, as well as $5.8 million in intangible and fixed assets contributed to the joint venture.
	On February 15, 2011, the Company completed the acquisition of 6,000 net undeveloped acres and additional working interests in the Pronghorn field in the Billings and Stark counties of North Dakota, for an aggregate purchase price of $40.0 million.
	2011 Divestiture
	On September 29, 2011, Whiting sold its interest in several non-core oil and gas producing properties located in the Karnes, Live Oak and DeWitt counties of Texas for total cash proceeds of $64.8 million, resulting in a pre-tax gain on sale of $12.3 million.  Whiting used the net proceeds from the property sale to repay a portion of the debt outstanding under its credit agreement.

LONGTERM_DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2013
LONG-TERM DEBT	'
LONG-TERM DEBT	'
	4.                                      LONG-TERM DEBT
	Long-term debt consisted of the following at December 31, 2013 and 2012 (in thousands):
		December 31,
		2013			2012
	Credit agreement	$	—		$	1,200,000
	7% Senior Subordinated Notes due 2014	—			250,000
	6.5% Senior Subordinated Notes due 2018	350,000			350,000
	5% Senior Notes due 2019	1,100,000			—
	5.75% Senior Notes due 2021, including unamortized debt premium of $3,834	1,203,834			—
	Total debt	$	2,653,834		$	1,800,000
	The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of December 31, 2013 (in thousands):
		2014			2015			2016		2017		2018
	Long-term debt	$	—		$	—		$	—	$	—	$	350,000
	Credit Agreement—Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), the Company’s wholly-owned subsidiary, has a credit agreement with a syndicate of banks that as of December 31, 2013 had a borrowing base of $2.8 billion, of which $1.2 billion has been committed by lenders and is available for borrowing.  The Company may increase the maximum aggregate amount of commitments under the credit agreement up to the $2.8 billion borrowing base if certain conditions are satisfied, including the consent of lenders participating in the increase.  As of December 31, 2013, the Company had $1,197.0 million of available borrowing capacity, which was net of $3.0 million in letters of credit with no borrowings outstanding.
	The credit agreement provides for interest only payments until April 2016, when the agreement expires and all outstanding borrowings are due.  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.  A portion of the revolving credit facility in an aggregate amount not to exceed $50.0 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, 2013, $47.0 million was available for additional letters of credit under the agreement.
	Interest 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 0.50% or an adjusted LIBOR rate plus 1.00%, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin in the table below.  Additionally, the Company also incurs commitment fees as set forth in the table below on the unused portion of the lesser of the aggregate commitments of the lenders or the borrowing base, and which are included as a component of interest expense.  The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates.
	Ratio of Outstanding Borrowings to Borrowing Base	Applicable		Applicable		Commitment
		Margin for Base		Margin for		Fee
		Rate Loans		Eurodollar Loans
	Less than 0.25 to 1.0	0.5	%	1.5	%	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	%	2	%	0.5	%
	Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0	1.25	%	2.25	%	0.5	%
	Greater than or equal to 0.90 to 1.0	1.5	%	2.5	%	0.5	%
	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 net assets of Whiting Oil and Gas.  As of December 31, 2013, total restricted net assets were $4,070.4 million, and the amount of retained earnings free from restrictions was $23.0 million.  The credit agreement requires the Company, as of the last day of any quarter, (i) to not exceed a total debt to the last four quarters’ EBITDAX ratio (as defined in the credit agreement) of 4.0 to 1.0 and (ii) to have a consolidated current assets to consolidated current liabilities ratio (as defined in the credit agreement and which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0.  The Company was in compliance with its covenants under the credit agreement as of December 31, 2013.
	The obligations of Whiting Oil and Gas under the credit agreement are secured by a first lien on substantially all of Whiting Oil and Gas’ properties included in the borrowing base for the credit agreement.  The Company has guaranteed the obligations of Whiting Oil and Gas under the credit agreement and has pledged the stock of Whiting Oil and Gas as security for its guarantee.
	Senior Notes and Senior Subordinated Notes—In September 2010, the Company issued at par $350.0 million of 6.5% Senior Subordinated Notes due October 2018.  The estimated fair value of these notes was $371.0 million as of December 31, 2013, based on quoted market prices for these debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy.
	Issuance of Senior Notes.  In September 2013, the Company issued at par $1,100.0 million of 5% Senior Notes due March 2019 and $800.0 million of 5.75% Senior Notes due March 2021, and issued at 101% of par an additional $400.0 million of 5.75% Senior Notes due March 2021 (collectively, the “Senior Notes”).  The Company used the net proceeds from these issuances to repay all of the debt outstanding under its credit agreement, to fund its $260.0 million acquisition of Williston Basin assets discussed in the Acquisitions and Divestitures footnote and to redeem all $250.0 million of its 7% Senior Subordinated Notes due February 2014 (the “2014 Notes”).  The Company plans to use the remainder of the net proceeds for general corporate purposes including capital expenditures.  The estimated fair values of the 2019 notes and the 2021 notes were $1,122.0 million and $1,260.0 million, respectively, as of December 31, 2013, based on quoted market prices for these debt securities, and such fair values are therefore designated as Level 1 within the valuation hierarchy.
	Redemption of Senior Subordinated Notes.  In October 2013, the Company paid $254.0 million to redeem all of its $250.0 million aggregate principal amount of the 2014 Notes at a redemption price of 101.595%.  Concurrent with this redemption, the Company paid all accrued and unpaid interest on the 2014 Notes up to but not including the redemption date.  The Company financed the redemption of the 2014 Notes with proceeds from the issuance of the Senior Notes, as discussed above.  As a result of the redemption, Whiting recognized a $4.4 million loss on early extinguishment of debt, which consisted of a cash charge of $4.0 million related to the redemption premium on the 2014 Notes and a non-cash charge of $0.4 million related to the acceleration of unamortized debt issuance costs.
	The Senior Notes are unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the Company’s secured indebtedness, which consists of Whiting Oil and Gas’ credit agreement.  The 6.5% Senior Subordinated Notes due 2018 (the “2018 Notes”) are also unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the Company’s senior debt, which currently consists of the Senior Notes and Whiting Oil and Gas’ credit agreement.  The Company’s obligations under the 2018 Notes and the Senior Notes are fully and unconditionally guaranteed by the Company’s 100%-owned subsidiary, Whiting Oil and Gas (the “Guarantor”).  Any subsidiaries other than the Guarantor 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, 2013
ASSET RETIREMENT OBLIGATIONS	'
ASSET RETIREMENT OBLIGATIONS	'
	5.                                      ASSET RETIREMENT OBLIGATIONS
	The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration (including removal of certain onshore and offshore facilities in California) in accordance with applicable local, state and federal laws.  The Company follows FASB ASC Topic 410, Asset Retirement and Environmental Obligations, to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations.  The current portions at December 31, 2013 and 2012 were $9.7 million and $11.6 million, respectively, and are included in accrued liabilities and other.  Revisions to the liability typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.  The following table provides a reconciliation of the Company’s asset retirement obligations for the year ended December 31, 2013 and 2012 (in thousands):
		Year Ended December 31,
		2013			2012
	Asset retirement obligation at January 1	$	97,818		$	69,721
	Additional liability incurred	17,535			9,292
	Revisions in estimated cash flows	12,225			23,162
	Accretion expense	10,608			7,263
	Obligations on sold properties	(3,630		)	(4		)
	Liabilities settled	(8,408		)	(11,616		)
	Asset retirement obligation at December 31	$	126,148		$	97,818

DERIVATIVE_FINANCIAL_INSTRUMEN

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2013
DERIVATIVE FINANCIAL INSTRUMENTS	'
DERIVATIVE FINANCIAL INSTRUMENTS	'
	6.                                      DERIVATIVE FINANCIAL INSTRUMENTS
	The Company is exposed to certain risks relating to its ongoing business operations, and Whiting uses derivative instruments to manage its commodity price risk.  Whiting follows FASB ASC Topic 815, Derivatives and Hedging, to account for its derivative financial instruments.
	Commodity Derivative Contracts—Historically, prices received for crude oil and natural gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions.  Whiting enters into derivative contracts, primarily costless collars and swaps, to achieve a more predictable cash flow by reducing its exposure to commodity price volatility.  Commodity derivative contracts are thereby used to ensure adequate cash flow to fund the Company’s capital programs and to manage returns on acquisitions and drilling programs.  Costless collars are designed to establish floor and ceiling prices on anticipated future oil or gas production, while swaps are designed to establish a fixed price for 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 Company does not enter into derivative contracts for speculative or trading purposes.
	Whiting Derivatives.  The table below details the Company’s costless collar derivatives, including its proportionate share of Trust II derivatives, entered into to hedge forecasted crude oil production revenues, as of February 6, 2014.
			Whiting Petroleum Corporation
	Derivative	Period	Contracted Crude Oil		Weighted Average NYMEX Price
	Instrument		Volumes (Bbl)		Collar Ranges for Crude Oil (per Bbl)
	Collars	Jan – Dec 2014	49,290		$ 80.00 - $122.50
	Three-way collars(1)	Jan – Dec 2014	15,280,000		$70.94 - $85.00 - $103.35
		Total	15,329,290
	(1)               A three-way collar is a combination of options: a sold call, a purchased put and a sold put.  The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract.  The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.
	In March 2013, Whiting entered into certain crude oil swap contracts in order to achieve more predictable cash flows and manage returns on certain oil and gas properties that the Company was considering for monetization.  Accordingly, the acquisition of these swap contracts and cash receipts from settlements of these swap positions have been reflected as an investing activity in the statement of cash flows.  On July 15, 2013, upon closing of the sale of the Postle Properties discussed in the Acquisitions and Divestitures footnote, these crude oil swaps were novated to the buyer.  Cash settlements that do not relate to investing derivatives or that do not have a significant financing element are reflected as operating activities in the statement of cash flows.
	Derivatives Conveyed to Whiting USA Trust II.  In connection with the Company’s conveyance in March 2012 of a term net profits interest to Trust II and related sale of 18,400,000 Trust II units to the public, the right to any future hedge payments made or received by Whiting on certain of its derivative contracts have been conveyed to Trust II, and therefore such payments will be included in Trust II’s calculation of net proceeds.  Under the terms of the aforementioned conveyance, Whiting retains 10% of the net proceeds from the underlying properties, which results in third-party public holders of Trust II units receiving 90%, and Whiting retaining 10%, of the future economic results of commodity derivative contracts conveyed to Trust II.  The relative ownership of the future economic results of such commodity derivatives is reflected in the tables below.  No additional hedges are allowed to be placed on Trust II assets.
	The 10% portion of Trust II derivatives that Whiting has retained the economic rights to (and which are also included in the first derivative table above) are as follows:
			Whiting Petroleum Corporation
	Derivative	Period	Contracted Crude Oil		NYMEX Price Collar Ranges for
	Instrument		Volumes (Bbl)		Crude Oil (per Bbl)
	Collars	Jan – Dec 2014	49,290		$80.00 - $122.50
	The 90% portion of Trust II derivative contracts of which Whiting has transferred the economic rights to third-party public holders of Trust II units (and which have not been reflected in the above tables) are as follows:
			Third-party Public Holders of Trust II Units
	Derivative	Period	Contracted Crude Oil		NYMEX Price Collar Ranges for
	Instrument		Volumes (Bbl)		Crude Oil (per Bbl)
	Collars	Jan – Dec 2014	443,610		$80.00 - $122.50
	Embedded Commodity Derivative Contract—In May 2011, Whiting entered into a long-term contract to purchase CO2 from 2015 through 2029 for use in its enhanced oil recovery project that is being carried out at its North Ward Estes field in Texas.  This contract contains a price adjustment clause that is linked to changes in NYMEX crude oil prices.  The Company has determined that the portion of this contract linked to NYMEX oil prices is not clearly and closely related to the host contract, and the Company has therefore bifurcated this embedded pricing feature from its host contract and reflected it at fair value in the consolidated financial statements.  As of December 31, 2013, the estimated fair value of the embedded derivative in this CO2 purchase contract was an asset of $36.4 million.
	Although CO2 is not a commodity that is actively traded on a public exchange, the market price for CO2 generally fluctuates in tandem with increases or decreases in crude oil prices.  When Whiting enters into a long-term CO2 purchase contract where the price of CO2 is fixed and does not adjust with changes in oil prices, the Company is exposed to the risk of paying higher than the market rate for CO2 in a climate of declining oil and CO2 prices.  This in turn could have a negative impact on the project economics of the Company’s CO2 flood at North Ward Estes.  As a result, the Company reduces its exposure to this risk by entering into certain CO2 purchase contracts which have prices that fluctuate along with changes in crude oil prices.
	Derivative Instrument Reporting—All derivative instruments are recorded in the consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion.  The following tables summarize the effects of commodity derivative instruments on the consolidated statements of income for the year ended December 31, 2013 and 2012 (in thousands):
			Gain (Loss) Reclassified from AOCI
			into Income (Effective Portion) (1)
	ASC 815 Cash Flow		Year Ended December 31,
	Hedging Relationships (1)	Income Statement Classification	2013			2012
	Commodity contracts	Gain (loss) on hedging activities	$	(1,958	)	$	2,338
	(1)               Effective April 1, 2009, the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively.  As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were being reclassified into earnings as the original hedged transactions affected income.  As of December 31, 2013, all amounts had been reclassified into earnings.
			(Gain) Loss Recognized in Income
	Not Designated as		Year Ended December 31,
	ASC 815 Hedges	Income Statement Classification	2013			2012
	Commodity contracts	Commodity derivative (gain) loss, net	$	20,503		$	(75,782	)
	Embedded commodity contracts	Commodity derivative (gain) loss, net	(12,701		)	(10,129		)
	Total		$	7,802		$	(85,911	)
	Offsetting of Derivative Assets and Liabilities.  With each individual derivative counterparty, the Company typically has numerous hedge positions that span a several-month time period and that typically result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability amount at the end of each reporting period.  The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract.  The following tables summarize the location and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands):
			December 31, 2013(1)
	Not Designated as	Balance Sheet Classification	Gross			Gross			Net
	ASC 815 Hedges		Recognized			Amounts			Recognized
			Assets/			Offset			Fair Value
			Liabilities						Assets/
									Liabilities
	Derivative assets:
	Commodity contracts	Prepaid expenses and other	$	23,752		$	(22,478	)	$	1,274
	Embedded commodity contracts	Other long-term assets	36,416			—			36,416
	Total derivative assets		$	60,168		$	(22,478	)	$	37,690
	Derivative liabilities:
	Commodity contracts	Current derivative liabilities	$	25,960		$	(22,478	)	$	3,482
	Total derivative liabilities		$	25,960		$	(22,478	)	$	3,482
			December 31, 2012(1)
	Not Designated as	Balance Sheet Classification	Gross			Gross			Net
	ASC 815 Hedges		Recognized			Amounts			Recognized
			Assets/			Offset			Fair Value
			Liabilities						Assets/
									Liabilities
	Derivative assets:
	Commodity contracts	Prepaid expenses and other	$	40,909		$	(31,437	)	$	9,472
	Commodity contracts	Other long-term assets	4,053			(2,189		)	1,864
	Embedded commodity contracts	Other long-term assets	24,038			(323		)	23,715
	Total derivative assets		$	69,000		$	(33,949	)	$	35,051
Derivative liabilities:
Commodity contracts	Current derivative liabilities	$	53,392		$	(31,437	)	$	21,955
Commodity contracts	Non-current derivative liabilities	3,867			(2,189		)	1,678
Embedded commodity contracts	Non-current derivative liabilities	323			(323		)	—
Total derivative liabilities		$	57,582		$	(33,949	)	$	23,633
(1)               Because counterparties to the Company’s derivative contracts are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above.
Contingent Features in Derivative Instruments.  None of the Company’s derivative instruments contain credit-risk-related contingent features.  Counterparties to the Company’s 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, 2013
FAIR VALUE MEASUREMENTS	'
FAIR VALUE MEASUREMENTS	'
	7.                                      FAIR VALUE MEASUREMENTS
	The Company follows FASB ASC Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements.  The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.  The three levels are defined as follows:
	·                  Level 1:  Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
	·                  Level 2:  Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
	·                  Level 3:  Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.
	A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.  The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level.
	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, 2013 and 2012, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):
		Level 1		Level 2			Level 3		Total Fair Value
									December 31,
									2013
	Financial Assets
	Commodity derivatives – current	$	—	$	1,274		$	—	$	1,274
	Embedded commodity derivatives – non-current	—		—			36,416		36,416
	Total financial assets	$	—	$	1,274		$	36,416	$	37,690
	Financial Liabilities
	Commodity derivatives – current	$	—	$	3,482		$	—	$	3,482
	Total financial liabilities	$	—	$	3,482		$	—	$	3,482
		Level 1		Level 2			Level 3		Total Fair Value
									December 31,
									2012
	Financial Assets
	Commodity derivatives – current	$	—	$	9,472		$	—	$	9,472
	Commodity derivatives – non-current	—		1,864			—		1,864
	Embedded commodity derivatives – non-current	—		—			23,715		23,715
	Total financial assets	$	—	$	11,336		$	23,715	$	35,051
	Financial Liabilities
	Commodity derivatives – current	$	—	$	21,955		$	—	$	21,955
	Commodity derivatives – non-current	—		1,678			—		1,678
	Total financial liabilities	$	—	$	23,633		$	—	$	23,633
	The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above:
	Commodity Derivatives.  Commodity derivative instruments consist of costless collars and swap contracts for crude oil.  The Company’s costless collars and swaps are valued based on an income approach.  Both the option and swap models consider various assumptions, such as quoted forward prices for commodities, time value and volatility factors.  These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy.  The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate.  The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
	Embedded Commodity Derivatives.  The embedded commodity derivative relates to a long-term CO2 purchase contract, which has a price adjustment clause that is linked to changes in NYMEX crude oil prices.  Whiting has determined that the portion of this contract linked to NYMEX oil prices is not clearly and closely related to its corresponding host contract, and the Company has therefore bifurcated this embedded pricing feature from the host contract and reflected it at fair value in its consolidated financial statements.  This embedded commodity derivative is valued based on an income approach.  The option model used in the valuation considers various assumptions, including quoted forward prices for commodities, LIBOR discount rates and either the Company’s or the counterparty’s nonperformance risk, as appropriate.
	The assumptions used in the CO2 contract valuation include inputs that are both observable in the marketplace as well as unobservable during the term of the contract.  With respect to forward prices for NYMEX crude oil where there is a lack of price transparency in certain future periods, such unobservable oil price inputs are significant to the CO2 contract valuation methodology, and the contract’s fair value is therefore designated as Level 3 within the valuation hierarchy.
	Level 3 Fair Value Measurements.  A third-party valuation specialist is utilized on a quarterly basis to determine the fair value of the embedded commodity derivative instrument designated as Level 3.  The Company reviews this valuation (including the related model inputs and assumptions) and analyzes changes in fair value measurements between periods.  The Company corroborates such inputs, calculations and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information from other published sources.
	The following table presents a reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy for the year ended December 31, 2013 and 2012 (in thousands):
		Year Ended December 31,
		2013		2012
	Fair value asset, beginning of period	$	23,715	$	12,980
	Unrealized gains (losses) on embedded commodity derivative contracts included in earnings(1)	12,701		10,735
	Transfers into (out of) Level 3	—		—
	Fair value asset, end of period	$	36,416	$	23,715
	(1)               Included in commodity derivative (gain) loss, net in the consolidated statements of income.
	Quantitative Information About Level 3 Fair Value Measurements.  The significant unobservable inputs used in the fair value measurement of the Company’s embedded commodity derivative contract designated as Level 3 are as follows:
		Fair Value at		Valuation		Unobservable		Range
		December 31, 2013		Technique		Input		(per Bbl)
		(in thousands)
	Embedded commodity derivative	$	36,416	Option model		Future prices of		$ 79.87 - $95.75
						NYMEX crude oil after
						March 31, 2022
	Sensitivity to Changes In Significant Unobservable Inputs.  As presented in the table above, the significant unobservable inputs used in the fair value measurement of Whiting’s embedded commodity derivative within its CO2 purchase contract are the future prices of NYMEX crude oil from April 2022 to December 2029.  Significant increases (decreases) in these unobservable inputs in isolation would result in a significantly lower (higher) fair value asset measurement.
	Nonrecurring Fair Value Measurements.  The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including proved oil and gas property impairments.  These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances.  The following tables present information about the Company’s non-financial assets and liabilities measured at fair value on a nonrecurring basis as of December 31, 2013 and 2012, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):
		Net Carrying		Fair Value Measurements Using							Loss (Before
		Value as of									Tax) Year
		December 31,									Ended
											December 31,
		2013		Level 1			Level 2		Level 3		2013
	Proved property impairments(1)	$	106,114	$	—		$	—	$	106,114	$	267,109
	(1)               During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373.2 million were written down to their fair value of $106.1 million, resulting in a non-cash impairment charge of $267.1 million.  The impairment consisted of (i) a $220.8 million write-down in the Rocky Mountains region and Michigan related to the decrease in the forward price curve for natural gas at December 31, 2013 and the associated decline in gas reserves in those areas and (ii) a $46.3 million write-down in the Rocky Mountains region related to well performance and associated changes in reserves during the fourth quarter of 2013.
		Net Carrying		Fair Value Measurements Using							Loss (Before
		Value as of									Tax) Year
		December 31,									Ended
											December 31,
		2012		Level 1			Level 2		Level 3		2012
Proved property impairments(1)	$	23,473	$	—		$	—	$	23,473	$	46,924
(1)               During the year ended December 31, 2012, proved oil and gas properties with a carrying amount of $70.4 million were written down to their fair value of $23.5 million, resulting in a non-cash impairment charge of $46.9 million.  The impairment consisted primarily of a $46.3 million write-down in the Rocky Mountains region related to changes in estimated reserves at December 31, 2012.
The following methods and assumptions were used to estimate the fair values of the non-financial liabilities in the tables above:
Proved Property Impairments.  Once the Company has determined that a proved property impairment has occurred, the cost of the property is written down to its fair value, which is determined using net discounted future cash flows from the producing property, and such discounted cash flows are developed using the income approach.  The discounted cash flows are based on management’s expectations for the future.  Unobservable inputs include estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on sales contract terms or NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate of 15% (all of which are designated as Level 3 inputs within the fair value hierarchy).

DEFERRED_COMPENSATION

DEFERRED COMPENSATION	12 Months Ended
	Dec. 31, 2013
DEFERRED COMPENSATION	'
DEFERRED COMPENSATION	'
	8.                                      DEFERRED COMPENSATION
	Production Participation Plan—The Company has a Production Participation Plan (the “Plan”) in which all employees participate.  On an annual basis, interests in oil and gas properties acquired, developed or sold during the year are allocated to the Plan as determined annually by the Compensation Committee of the Company’s Board of Directors.  Once allocated, the interests (not legally conveyed) are fixed.  Interest allocations prior to 1995 consisted of 2%-3% overriding royalty interests.  Interest allocations since 1995 have been 1.75%-5% of oil and gas sales less lease operating expenses and production taxes.
	Payments of 100% of the year’s Plan interests to employees and the vested percentages of former employees in the year’s Plan interests are made annually in cash after year-end.  Accrued compensation expense under the Plan for the years ended December 31, 2013, 2012 and 2011 amounted to $66.5 million, $44.7 million and $34.1 million, respectively, charged to general and administrative expense and $6.8 million, $4.6 million and $4.2 million, respectively, charged to exploration expense.
	Employees vest in the Plan ratably at 20% per year over a five-year period.  Pursuant to the terms of the Plan, (i) employees who terminate their employment with the Company are entitled to receive their vested allocation of future Plan year payments on an annual basis; (ii) employees will become fully vested at age 62, regardless of when their interests would otherwise vest; and (iii) any forfeitures inure to the benefit of the Company.
	The Company uses average historical prices to estimate the vested long-term Production Participation Plan liability.  At December 31, 2013, the Company used three-year average historical NYMEX prices of $95.60 for crude oil and $3.49 for natural gas to estimate this liability.  The Company records the expense associated with changes in the present value of estimated future payments under the Plan as a separate line item in the consolidated statements of income.  If the Company were to terminate the Plan or upon a change in control of the Company (as defined in the Plan), all employees fully vest and the Company would distribute to each Plan participant an amount, based upon the valuation method set forth in the Plan, in a lump sum payment twelve months after the date of termination or within one month after a change in control event.  Based on current strip prices at December 31, 2013, if the Company elected to terminate the Plan or if a change of control event occurred, it is estimated that the fully vested lump sum cash payment to employees would approximate $186.7 million.  This amount includes $19.2 million attributable to proved undeveloped oil and gas properties and $73.3 million relating to the short-term portion of the Plan liability, which has been reflected as a current payable in accrued liabilities and other, and was paid in January and February 2014.  The ultimate sharing contribution for proved undeveloped oil and gas properties will be awarded in the year of Plan termination or change of control.  However, the Company has no intention to terminate the Plan.
	The following table presents changes in the Plan’s estimated long-term liability (in thousands):
		Year Ended December 31,
		2013			2012
	Long-term Production Participation Plan liability at January 1	$	94,483		$	80,659
	Change in liability for accretion, vesting, changes in estimates and new Plan year activity	66,284			63,135
	Accrued compensation expense reflected as a current liability	(73,264		)	(49,311		)
	Long-term Production Participation Plan liability at December 31	$	87,503		$	94,483
	Of the aggregate $73.3 million of accrued compensation under the Plan as of December 31, 2013, $23.9 million relates to the sale of the Postle Properties, which is further described in the Acquisitions and Divestitures footnote.  This property sale also resulted in an offsetting benefit of $19.4 million realized related to the reduction in the Company’s long-term Plan liability.
	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 2013, 2012 and 2011 were $7.9 million, $5.9 million and $5.0 million, respectively.  Employees vest in employer contributions at 20% per year of completed service.

SHAREHOLDERS_EQUITY_AND_NONCON

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST	12 Months Ended
	Dec. 31, 2013
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST	'
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST	'
	9.                                      SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
	Common Stock—In May 2011, Whiting’s stockholders approved an amendment to the Company’s Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 175,000,000 shares to 300,000,000 shares.
	Stock Split.  On January 26, 2011, the Company’s Board of Directors approved a two-for-one split of the Company’s shares of common stock to be effected in the form of a stock dividend.  As a result of the stock split, stockholders of record on February 7, 2011 received one additional share of common stock for each share of common stock held.  The additional shares of common stock were distributed on February 22, 2011.  Concurrently with the payment of such stock dividend in February 2011, there was a transfer from additional paid-in capital to common stock of $0.1 million, which amount represents $0.001 per share (being the par value thereof) for each share of common stock so issued.  The common stock dividend resulted in the conversion price for Whiting’s 6.25% Convertible Perpetual Preferred Stock being adjusted from $43.4163 to $21.70815.
	6.25% Convertible Perpetual Preferred Stock—In June 2009, the Company completed a public offering of 6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a price of $100.00 per share.  As a result of voluntary conversions and the Company exercising its right to mandatorily convert shares of preferred stock effective June 27, 2013, all 172,129 shares of preferred stock outstanding on March 31, 2013, were converted into 792,919 shares of common stock.  As of December 31, 2013, no shares of preferred stock remained issued or outstanding.
	Each holder of the preferred stock was entitled to an annual dividend of $6.25 per share to be paid quarterly in cash, common stock or a combination thereof on March 15, June 15, September 15 and December 15, when and if such dividend had been declared by Whiting’s board of directors.
	Equity Incentive Plan—At the Company’s 2013 Annual Meeting held on May 7, 2013, shareholders approved the Whiting Petroleum Corporation 2013 Equity Incentive Plan (the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and includes the authority to issue 5,300,000 shares of the Company’s common stock.  Upon shareholder approval of the 2013 Equity Plan, the 2003 Equity Plan was terminated.  The 2003 Equity Plan continues to govern awards that were outstanding as of the date of its termination, which remain in effect pursuant to their terms. Any shares netted or forfeited after May 7, 2013 under the 2003 Equity Plan will be available for future issuance under the 2013 Equity Plan. Under the 2013 Equity Plan, no employee or officer participant may be granted options for more than 600,000 shares of common stock, stock appreciation rights relating to more than 600,000 shares of common stock, or more than 300,000 shares of restricted stock during any calendar year.  As of December 31, 2013, 5,380,594 shares of common stock remained available for grant under the 2013 Equity Plan.
	For the years ended December 31, 2013, 2012 and 2011, total stock compensation expense recognized for restricted share awards and stock options was $22.4 million, $18.2 million and $13.5 million, respectively.
	Restricted Shares.  Restricted stock awards for executive officers and employees generally vest ratably over a three-year service period, while awards to directors generally vest ratably over a one or three-year service period.  The Company uses historical data and projections to estimate expected employee behaviors related to restricted stock forfeitures.  The expected forfeitures are then included as part of the grant date estimate of compensation cost.  For service-based restricted stock awards, the grant date fair value is determined based on the closing bid price of the Company’s common stock on the grant date.
	In January 2013, 2012 and 2011, 751,872 shares, 444,501 shares and 201,420 shares, respectively, of restricted stock, subject to certain market-based vesting criteria in addition to the standard three-year service condition, were granted to executive officers under the Equity Plan.  Vesting each year is subject to the condition that Whiting’s stock price increases by a greater percentage (or decreases by a lesser percentage) than the average percentage increase (or decrease, respectively) of the stock prices of a peer group of companies.  The market-based conditions must be met in order for the stock awards to vest, and it is therefore possible that no shares could vest in one or more of the three-year vesting periods.  However, the Company recognizes compensation expense for awards subject to market conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense is not reversed if vesting does not actually occur.
	For these awards subject to market conditions, the grant date fair value was estimated using a Monte Carlo valuation model.  The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment.  Expected volatility was calculated based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period.  The key assumptions used in valuing the market-based restricted shares were as follows:
		2013		2012		2011
	Number of simulations	65,000		65,000		65,000
	Expected volatility	43.1	%	51.9	%	75.8	%
	Risk-free rate	0.41	%	0.35	%	1	%
	Dividend yield	—		—		—
	The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation model was $23.01 per share, $29.45 per share and $42.20 per share in January 2013, 2012 and 2011, respectively.
	The following table shows a summary of the Company’s nonvested restricted stock as of December 31, 2011, 2012 and 2013 as well as activity during the years then ended:
		Number		Weighted Average
		of Shares		Grant Date
				Fair Value
	Restricted stock awards nonvested, January 1, 2011	869,370		$	16.27
	Granted	304,355		48.48
	Vested	(429,136	)	15.32
	Forfeited	(20,194	)	33.53
	Restricted stock awards nonvested, December 31, 2011	724,395		29.88
	Granted	592,400		34.45
	Vested	(357,170	)	17.91
	Forfeited	(8,599	)	51.72
	Restricted stock awards nonvested, December 31, 2012	951,026		37.02
	Granted	940,792		27.59
	Vested	(347,824	)	35.32
	Forfeited	(99,684	)	30.95
	Restricted stock awards nonvested, December 31, 2013	1,444,310		$	31.71
	As of December 31, 2013, there was $11.8 million of total unrecognized compensation cost related to unvested restricted stock granted under the stock incentive plans.  That cost is expected to be recognized over a weighted average period of 1.7 years. For the years ended December 31, 2013, 2012 and 2011, the total fair value of restricted stock vested was $16.8 million, $18.9 million and $26.0 million, respectively.
	Stock Options.  In January 2012 and 2011, 45,359 stock options and 80,820 stock options, respectively, were granted under the 2003 Equity Plan to certain executive officers of the Company with exercise prices equal to the closing market price of the Company’s common stock on the grant date.  There were no stock options granted under either the 2003 Equity Plan or the 2013 Equity Plan during 2013.  These 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 Company uses a Black-Scholes option-pricing model to estimate the fair value of stock option awards.  Because the Company first granted stock options in 2009, it does not have historical exercise data upon which to estimate the expected term of the options.  As such, the Company has elected to estimate the expected term of the stock options granted using the “simplified” method for “plain vanilla” options.  The expected volatility at the grant date is based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is determined based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options.  The following table summarizes the assumptions used to estimate the grant date fair value of stock options awarded in each respective year:
		2012		2011
	Risk-free interest rate	1.19	%	2.47	%
	Expected volatility	61.4	%	59.3	%
	Expected term	6.0 yrs.		6.0 yrs.
	Dividend yield	—		—
	The grant date fair value of the stock options awarded, as determined by the Black-Scholes valuation model, was $28.88 per share and $34.15 per share in January 2012 and 2011, respectively.
	The following table shows a summary of the Company’s stock options outstanding as of December 31, 2011, 2012 and 2013 as well as activity during the years then ended:
		Number of		Weighted			Aggregate		Weighted
		Options		Average			Intrinsic		Average
				Exercise Price			Value		Remaining
				per Share			(in thousands)		Contractual
									Term
									(in years)
	Options outstanding at January 1, 2011	296,516		$	16.78
	Granted	80,820		60.28
	Exercised	—		—			$	—
	Forfeited or expired	—		—
	Options outstanding at December 31, 2011	377,336		26.09
	Granted	45,359		51.22
	Exercised	—		—			$	—
	Forfeited or expired	—		—
	Options outstanding at December 31, 2012	422,695		28.79
	Granted	—		—
	Exercised	—		—			$	—
	Forfeited or expired	(1,855	)	60.28
	Options outstanding at December 31, 2013	420,840		$	28.65		$	13,979.60	5.9
	Options vested and expected to vest at December 31, 2013	420,840		$	28.65		$	13,979.60	5.9
Options exercisable at December 31, 2013	365,511		$	24.61		$	13,617.80	5.7
Unrecognized compensation cost as of December 31, 2013 related to unvested stock option awards was $0.2 million, which is expected to be recognized over a period of one year.
Rights Agreement—In 2006, the Board of Directors of the Company declared a dividend of one preferred share purchase right (a “Right”) for each outstanding share of common stock of the Company payable to the stockholders of record as of March 2, 2006.  As a result of the two-for-one split of the Company’s common stock effective February 22, 2011, one-half of a Right is now associated with each share of common stock.  Each Right entitles the registered holder to purchase from the Company one one-hundredth of a share of Series A Junior Participating Preferred Stock, par value $0.001 per share (“Preferred Shares”), of the Company at a price of $180.00 per one one-hundredth of a Preferred Share, subject to adjustment.  If any person becomes a 15% or more stockholder of the Company, then each Right (subject to certain limitations) will entitle its holder to purchase, at the Right’s then current exercise price, a number of shares of common stock of the Company or of the acquirer having a market value at the time of twice the Right’s per share exercise price.  The Company’s Board of Directors may redeem the Rights for $0.001 per Right at any time prior to the time when the Rights become exercisable.  Unless the Rights are redeemed, exchanged or terminated earlier, they will expire on February 23, 2016.
Noncontrolling Interest—The noncontrolling interest represents an unrelated third party’s 25% ownership interest in Sustainable Water Resources, LLC.  The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):
	Year Ended December 31,
	2013			2012
Balance at January 1	$	8,184		$	8,274
Net income (loss)	(52		)	(90		)
Balance at December 31	$	8,132		$	8,184

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2013
INCOME TAXES	'
INCOME TAXES	'
	10.                              INCOME TAXES
	Income tax expense consists of the following (in thousands):
		Year Ended December 31,
		2013			2012			2011
	Current income tax expense (refund):
	Federal	$	7,060		$	—		$	107
	State	(6,074		)	(669		)	3,746
	Total current income tax expense	986			(669		)	3,853
	Deferred income tax expense:
	Federal	196,787			233,468			272,653
	State	8,095			15,113			12,185
	Total deferred income tax expense	204,882			248,581			284,838
	Total	$	205,868		$	247,912		$	288,691
	Income tax expense differed from amounts that would result from applying the U.S. statutory income tax rate (35%) to income before income taxes as follows (in thousands):
		Year Ended December 31,
		2013			2012			2011
	U.S. statutory income tax expense	$	200,155		$	231,704		$	273,112
	State income taxes, net of federal benefit	13,962			14,444			16,602
	State income tax credits	(10,525		)	—			—
	Statutory depletion	(796		)	(620		)	(697		)
	Enacted changes in state tax laws	(1,416		)	—			(1,842		)
	Permanent items	2,122			1,524			1,420
	Other	2,366			860			96
	Total	$	205,868		$	247,912		$	288,691
	The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2013 and 2012 were as follows (in thousands):
		Year Ended December 31,
		2013			2012
	Deferred income tax assets:
	Net operating loss carryforward	$	438,922		$	520,980
	Derivative instruments	—			19,957
	Production Participation Plan liability	32,245			34,865
	Tax sharing liability	9,439			8,312
	Asset retirement obligations	23,642			19,759
	Underwriter fees	10,974			12,677
	Restricted stock compensation	13,384			9,852
	Enhanced oil recovery credit carryforwards	7,946			7,946
	Alternative minimum tax credit carryforwards	18,452			11,391
	Foreign tax credit carryforwards	1,230			1,230
	Other	2,004			1,508
	Total deferred income tax assets	558,238			648,477
	Less valuation allowances	(1,230		)	(1,230		)
	Net deferred income tax assets	557,008			647,247
	Deferred income tax liabilities:
	Oil and gas properties	1,675,916			1,555,142
	Trust distributions	149,332			165,180
	Derivative instruments	10,438			—
	Total deferred income tax liabilities	1,835,686			1,720,322
	Total net deferred income tax liabilities	$	1,278,678		$	1,073,075
	As of December 31, 2013, we had federal net operating loss (“NOL”) carryforwards of $1,255.2 million.  Of this amount, $50.5 million in NOL carryforwards relate to tax deductions for stock compensation that exceed stock compensation costs recognized for financial statement purposes.  The benefit of these excess tax deductions will not be recognized as an NOL in the Company’s financial statements, until the related deductions reduce taxes payable and are thereby realized.  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 impact the amount of such carryforwards.  If unutilized, the federal NOL will expire between 2027 and 2033, and the state NOLs will expire between 2014 and 2033.
	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, 2013, the Company had recognized aggregate EOR credits of $7.9 million that are available to offset regular federal income taxes in the future.  These credits can be carried forward and will expire between 2023 and 2025.  Federal EOR credits are subject to phase-out according to the level of average domestic crude oil prices.  The EOR credit has been phased-out since 2006, but this phase-out affects only the periods for which EOR credits can be captured and not the periods in which such credits can be utilized.
	The Company is subject to the alternative minimum tax (“AMT”) principally due to its significant intangible drilling cost deductions.  As of December 31, 2013, the Company had AMT credits totaling $18.5 million that are available to offset future regular federal income taxes.  These credits do not expire and can be carried forward indefinitely.
	At December 31, 2013, the Company’s foreign tax credit carryforwards totaled $1.2 million, which will expire between 2014 and 2016.  As of December 31, 2013, a valuation allowance of $1.2 million was established in full for the foreign tax credit carryforwards because the Company determined that it was more likely than not that the benefit from these deferred tax assets will not be realized due to the divestiture of all foreign operations.
	Net deferred income tax liabilities were classified in the consolidated balance sheets as follows (in thousands):
		Year Ended December 31,
		2013			2012
	Assets:
	Current deferred income taxes	$	—		$	—
	Liabilities:
	Current deferred income taxes	648			9,394
	Non-current deferred income taxes	1,278,030			1,063,681
	Net deferred income tax liabilities	$	1,278,678		$	1,073,075
	The following table summarizes the activity related to the Company’s liability for unrecognized tax benefits (in thousands):
		Year Ended December 31,
	2013			2012			2011
Beginning balance at January 1	$	170		$	299		$	299
Decrease related to tax position taken in a prior period	—			(129		)	—
Ending balance at December 31	$	170		$	170		$	299
Included in the unrecognized tax benefit balance at December 31, 2013, are $0.2 million of tax positions, the allowance of which would positively affect the annual effective income tax rate.  For the year ended December 31, 2013, the Company did not recognize any interest or penalties with respect to unrecognized tax benefits, nor did the Company have any such interest or penalties previously accrued.  The Company believes that it is reasonably possible that no increases or decreases to unrecognized tax benefits will occur in the next twelve months.
The Company files income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations.  The 2010 through 2013 tax years generally remain subject to examination by federal and state tax authorities.

EARNINGS_PER_SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2013
EARNINGS PER SHARE	'
EARNINGS PER SHARE	'
	11.                               EARNINGS PER SHARE
	The reconciliations between basic and diluted earnings per share are as follows (in thousands, except per share data):
		Year Ended December 31,
		2013			2012			2011
	Basic Earnings Per Share
	Numerator:
	Net income available to shareholders	$	366,055		$	414,189		$	491,687
	Preferred stock dividends (1)	(494		)	(1,077		)	(1,077		)
	Net income available to common shareholders, basic	$	365,561		$	413,112		$	490,610
	Denominator:
	Weighted average shares outstanding, basic	118,260			117,601			117,345
	Diluted Earnings Per Share
	Numerator:
	Net income available to common shareholders, basic	$	365,561		$	413,112		$	490,610
	Preferred stock dividends	538			1,077			1,077
	Adjusted net income available to common shareholders, diluted	$	366,099		$	414,189		$	491,687
	Denominator:
	Weighted average shares outstanding, basic	118,260			117,601			117,345
	Restricted stock and stock options	957			633			529
	Convertible perpetual preferred stock	371			794			794
	Weighted average shares outstanding, diluted	119,588			119,028			118,668
	Earnings per common share, basic	$	3.09		$	3.51		$	4.18
	Earnings per common share, diluted	$	3.06		$	3.48		$	4.14
	(1)               For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated.  There were no accumulated dividend adjustments for the years ended December 31, 2012 and 2011.
	For the year ended December 31, 2013, the diluted earnings per share calculation excludes the dilutive effect of (i) 173,778 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2013, and (ii) 8,689 common shares for stock options that were out-of-the-money.  For the year ended December 31, 2012, the diluted earnings per share calculation excludes (i) the dilutive effect of 141,807 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2012, and (ii) the anti-dilutive effect of 7,720 common shares for stock options that were out-of-the-money.  For the year ended December 31, 2011, the diluted earnings per share calculation excludes the dilutive effect of (i) 113,228 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2011, and (ii) 2,285 common shares for stock options that were out-of-the-money.

RELATED_PARTY_TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2013
RELATED PARTY TRANSACTIONS	'
RELATED PARTY TRANSACTIONS	'
	12.                               RELATED PARTY TRANSACTIONS
	Whiting USA Trust I—As a result of Whiting’s retained ownership of 15.8%, or 2,186,389 units in Whiting USA Trust I, it is a related party of the Company.  The following table summarizes the related party receivable and payable balances between the Company and Trust I as of December 31, 2013 and 2012 (in thousands):
		December 31,
		2013		2012
	Assets
	Unit distributions due from Trust I (1)	$	1,093	$	929
	Liabilities
	Unit distributions payable to Trust I (2)	$	6,932	$	5,731
	(1)               This amount represents Whiting’s 15.8% interest in the net proceeds due from Trust I and is included within accounts receivable trade, net in the Company’s consolidated balance sheets.
	(2)               This amount represents net proceeds from Trust I’s underlying properties that the Company has received between the last Trust I distribution date and December 31, 2013 and 2012, respectively, but which the Company has not yet distributed to Trust I as of December 31, 2013 and 2012, respectively.  Due to ongoing processing of Trust I revenues and expenses after December 31, 2013 and 2012, the amount of Whiting’s next scheduled distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this amount.  These amounts are included within accounts payable trade in the Company’s consolidated balance sheet.
	For the year ended December 31, 2013, Whiting paid $30.7 million, net of state tax withholdings, in unit distributions to Trust I and received $4.7 million in distributions back from Trust I pursuant to its retained ownership in 2,186,389 Trust I units.
	Tax Sharing Liability—Prior to Whiting’s initial public offering in November 2003, it was a wholly-owned indirect subsidiary of Alliant Energy Corporation (“Alliant Energy”), and when the transactions discussed below were entered into, Alliant Energy was a related party of the Company.  As of December 31, 2004 and thereafter, Alliant Energy was no longer a related party.
	In 2003, the Company entered into a Tax Separation and Indemnification Agreement with Alliant Energy, whereby the Company and Alliant Energy made certain tax elections with the effect that the tax bases of Whiting’s assets were increased. Such additional tax bases have resulted in increased income tax deductions for Whiting and, accordingly, have reduced income taxes otherwise payable by Whiting.  Under this Tax Separation and Indemnification Agreement, the Company agreed to pay to Alliant Energy (each year from 2004 to 2013) 90% of the tax benefits the Company realized annually as a result of this step-up in tax bases.  In 2014, Whiting is obligated to pay Alliant the present value of 90% of the remaining tax benefits expected to result from its increased tax bases, which payout assumes all such tax benefits will be realized in future years.
	The final remaining payment of $23.9 million due Alliant Energy under this agreement has been reflected in the Company’s consolidated balance sheets as a current liability at December 31, 2013.  During 2013, 2012 and 2011, the Company made payments of $1.8 million, $2.3 million and $1.9 million, respectively, under this agreement and recognized interest expense of $3.1 million, $2.2 million and $2.1 million, respectively.
	Alliant Energy Guarantee—The Company holds a 6% working interest in three offshore platforms in California and the related onshore plant and equipment.  Alliant Energy has guaranteed the Company’s obligation in the abandonment of these assets.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2013
COMMITMENTS AND CONTINGENCIES	'
COMMITMENTS AND CONTINGENCIES	'
	13.                               COMMITMENTS AND CONTINGENCIES
	The table below shows the Company’s minimum future payments under non-cancelable operating leases and unconditional purchase obligations as of December 31, 2013 (in thousands):
		Payments due by period
		2014		2015		2016		2017		2018		Thereafter		Total
	Non-cancelable leases	$	6,279	$	5,872	$	5,387	$	5,250	$	4,629	$	1,374	$	28,791
	Drilling rig contracts	87,610		48,531		1,755		—		—		—		137,896
	Construction and drilling contract	31,066		—		2,900		6,900		4,100		—		44,966
	Total	$	124,955	$	54,403	$	10,042	$	12,150	$	8,729	$	1,374	$	211,653
	Non-cancelable Leases—The Company leases 172,400 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2018, 47,900 square feet of office space in Midland, Texas expiring in 2020 and 20,000 square feet of office space in Dickinson, North Dakota expiring in 2016.  In addition, the Company entered into a lease for several residential apartments in Watford City and Dickinson, North Dakota under an operating lease arrangement expiring in 2015.  Rental expense for 2013, 2012 and 2011 amounted to $5.0 million, $5.7 million and $4.4 million, respectively.  Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 2013 are shown in the table above.
	Drilling Rig Contracts—The Company currently has 12 drilling rigs under long-term contract, of which six drilling rigs expire in 2014, four in 2015 and two in 2016.  All of these rigs are operating in the Rocky Mountains region.  As of December 31, 2013, early termination of the remaining contracts would require termination penalties of $101.1 million, which would be in lieu of paying the remaining drilling commitments of $137.9 million.  No other drilling rigs working for the Company are currently under long-term contracts or contracts that cannot be terminated at the end of the well that is currently being drilled.  During 2013, 2012 and 2011, the Company made payments of $92.8 million, $101.1 million and $49.8 million, respectively, under these long-term contracts, which are initially capitalized as a component of oil and gas properties and either depleted in future periods or written off as exploration expense.  Two of these drilling rigs have price adjustment clauses that make their corresponding day rates fluctuate, and this component of those purchase obligations is therefore variable.  Minimum drilling commitments under the terms of these contracts as of December 31, 2013 are shown in the table above.
	Construction and Drilling Contract—The Company entered into a contract whereby it is obligated to spend up to $51.4 million on the construction of certain facilities and field infrastructure and the drilling of forty-six CO2 wells in its Bravo Dome field.  As of December 31, 2013, the Company had spent $6.4 million towards meeting this contractual commitment and had a remaining capital expenditure obligation of $45.0 million.  If the Company fails to spend the required amounts by the dates set forth in the agreement, it will be required to pay the remaining unspent capital expenditures as liquidated damages.  However, the Company expects to fulfill its obligations under this contract and therefore avoid any payments for deficiencies.  The Company’s remaining financial commitments under this agreement as of December 31, 2013 are shown in the table above.  The Company does not have any volumetric CO2 delivery or supply commitments associated with this contract.
	Purchase Contracts—The Company has three take-or-pay purchase agreements, one agreement expiring in December 2014, one agreement expiring in December 2017 and one agreement expiring in December 2029, whereby the Company has committed to buy certain volumes of CO2 for use in its EOR project in the North Ward Estes field in Texas.  The purchase agreements are with two different suppliers.  Under the terms of the agreements, the Company is obligated to purchase a minimum daily volume of CO2 (as calculated on an annual basis) or else pay for any deficiencies at the price in effect when the minimum delivery was to have occurred.  In addition, the Company has one ship-or-pay agreement, expiring in December 2017, whereby it has committed to transport a minimum daily volume of CO2 via a certain pipeline or else pay for any deficiencies at a price stipulated in the contract.
	The CO2 volumes planned for use in the Company’s EOR project in the North Ward Estes field currently exceed the minimum daily volumes specified in all of these agreements.  Therefore, the Company expects to avoid any payments for deficiencies.  During 2013, 2012 and 2011, purchases and transportation of CO2 amounted to $88.1 million, $86.0 million and $69.8 million, respectively.  Although minimum daily quantities are specified in the agreements, the actual CO2 volumes purchased or transported and their corresponding unit prices are variable over the term of the contracts.  As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above.  As of December 31, 2013, the Company estimated future commitments under these purchase agreements to approximate $632.6 million through 2029.
	Delivery Commitments—The Company has various physical delivery contracts which require the Company to deliver fixed volumes of natural gas and crude oil.  As of December 31, 2013, the Company had delivery commitments of 4.0 Bcf of natural gas for the year ended December 31, 2014, which relate to gas production at its Boies Ranch field in Rio Blanco County, Colorado and its Flat Rock field in Uintah County, Utah.  As of December 31, 2013, the Company also had delivery commitments of 9.1 MMBbl, 11.0 MMBbl, 12.8 MMBbl, 14.6 MMBbl and 16.4 MMBbl of crude oil for the years ended December 31, 2015, 2016, 2017, 2018 and 2019, respectively.  These delivery commitments relate to crude oil production at Whiting’s Redtail field in the DJ Basin in Weld County, Colorado.  The Company anticipates that future production from this field will be sufficient to meet the delivery commitments under these physical delivery contracts, and the Company therefore expects to avoid any payments for deficiencies.  As a result, there is no financial obligation under these contracts.
	Litigation—The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business.  We accrue 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.  Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued at December 31, 2013 or 2012.  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.

OIL_AND_GAS_ACTIVITIES

OIL AND GAS ACTIVITIES	12 Months Ended
	Dec. 31, 2013
OIL AND GAS ACTIVITIES	'
OIL AND GAS ACTIVITIES	'
	14.                               OIL AND GAS ACTIVITIES
	The Company’s oil and gas activities for 2013, 2012 and 2011 were entirely within the United States.  Costs incurred in oil and gas producing activities were as follows (in thousands):
		Year Ended December 31,
		2013			2012			2011
	Development(1)	$	2,132,824		$	1,667,182		$	1,245,150
	Proved property acquisition	232,572			19,785			4,324
	Unproved property acquisition	174,103			119,175			191,482
	Exploration	363,234			436,084			400,823
	Total	$	2,902,733		$	2,242,226		$	1,841,779
	(1)               During 2013, 2012 and 2011, non-cash additions to oil and gas properties of $29.8 million, $36.3 million and $4.9 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s oil and gas wells, are included in development costs in the table above.
	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,
		2013			2012			2011
	Beginning balance at January 1	$	108,861		$	90,519		$	4,434
	Additions to capitalized exploratory well costs pending the determination of proved reserves	281,951			384,223			354,962
	Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(291,962		)	(358,625		)	(267,847		)
	Capitalized exploratory well costs charged to expense	(13,472		)	(7,256		)	(1,030		)
	Ending balance at December 31	$	85,378		$	108,861		$	90,519
	At December 31, 2013, the Company had $10.3 million of capitalized exploratory well costs related to one well that was in progress for a period of greater than one year after the completion of drilling.  This well is located in the Company’s Rocky Mountains region.  Of the $10.3 million in costs capitalized for this exploratory well, $7.7 million and $2.6 million were incurred in 2013 and 2012, respectively.  Due to the high nitrogen and CO2 content resident in the natural gas produced by this well, processing is required before this well’s gas can be sold.  Before Whiting can begin building a CO2 removal and compression skid and gas pipeline for this well, however, the Company needs to first determine if there are sufficient quantities of natural gas reserves in this field to make the construction of gas processing facilities economically justifiable.  As a result, the Company is continuing to drill additional wells in this area to delineate the field and to make a determination as to the aggregate quantity of natural gas reserves that can be produced from this reservoir.

DISCLOSURES_ABOUT_OIL_AND_GAS_

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2013
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	'
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	'
	15.                               DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
	For all years presented our independent petroleum engineers independently estimated all of the proved, probable and possible reserve quantities included in this annual report.  In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.  The independent petroleum engineers, Cawley, Gillespie & Associates, Inc., evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2013.  Proved reserve estimates included herein conform to the definitions prescribed by the U.S. Securities and Exchange Commission.  Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
	As of December 31, 2013, all of the Company’s oil and gas reserves are attributable to properties within the United States.  A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2011, 2012 and 2013 are as follows:
		Oil		NGLs		Natural Gas		Total
		(MBbl)		(MBbl)		(MMcf)		(MBOE)
	Balance—January 1, 2011	224,196		30,082		303,544		304,869
	Extensions and discoveries	39,660		5,024		23,211		48,552
	Sales of minerals in place	(579	)	(632	)	(9,759	)	(2,837	)
	Purchases of minerals in place	114		58		1,639		445
	Production	(18,299	)	(2,074	)	(26,443	)	(24,780	)
	Revisions to previous estimates	15,052		5,151		(7,217	)	19,000
	Balance—December 31, 2011	260,144		37,609		284,975		345,249
	Extensions and discoveries	68,134		6,526		40,915		81,479
	Sales of minerals in place	(7,960	)	(320	)	(13,987	)	(10,611	)
	Production	(23,139	)	(2,766	)	(25,827	)	(30,209	)
	Revisions to previous estimates	4,106		(951	)	(61,812	)	(7,148	)
	Balance—December 31, 2012	301,285		40,098		224,264		378,760
	Extensions and discoveries	88,293		9,830		63,893		108,772
	Sales of minerals in place	(36,992	)	(4,777	)	(12,411	)	(43,838	)
	Purchases of minerals in place	14,543		1,311		7,751		17,146
	Production	(27,035	)	(2,821	)	(26,917	)	(34,342	)
	Revisions to previous estimates	7,327		1,228		20,934		12,044
	Balance—December 31, 2013	347,421		44,869		277,514		438,542
	Proved developed reserves:
	December 31, 2010	160,088		18,321		220,530		215,164
	December 31, 2011	180,975		22,109		211,297		238,300
	December 31, 2012	190,845		24,204		160,893		241,864
	December 31, 2013	198,204		23,721		183,129		252,446
	Proved undeveloped reserves:
	December 31, 2010	64,108		11,761		83,014		89,705
	December 31, 2011	79,169		15,500		73,678		106,949
	December 31, 2012	110,440		15,894		63,371		136,896
	December 31, 2013	149,217		21,148		94,385		186,096
	Notable changes in proved reserves for the year ended December 31, 2013 included:
	·                  Extensions and discoveries.  In 2013, total extensions and discoveries of 108.8 MMBOE were primarily attributable to successful drilling in the Redtail, Sanish, Missouri Breaks, Hidden Bench and Pronghorn fields.  The new producing wells in these areas and their related proved undeveloped locations added during the year increased the Company’s proved reserves.
	·                  Sales of minerals in place.  In 2013, total sales of minerals in place of 43.8 MMBOE were primarily attributable to the disposition of the Postle Properties, further described in the Acquisitions and Divestitures footnote, which decreased the Company’s proved reserves.
	·                  Purchases of minerals in place.  In 2013, total purchases of minerals in place of 17.1 MMBOE were primarily attributable to the acquisition of 121 producing oil and gas wells and undeveloped acreage in the Williston Basin, further described in the Acquisitions and Divestitures footnote, which increased the Company’s proved reserves.
	·                  Revisions to previous estimates.  In 2013, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 12.0 MMBOE.  Included in these revisions were (i) 4.9 MMBOE of upward adjustments caused by higher crude oil and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2013 as compared to December 31, 2012 and (ii) 7.1 MMBOE of net upward adjustments attributable to reservoir analysis and well performance.
	Notable changes in proved reserves for the year ended December 31, 2012 included:
	·                  Extensions and discoveries.  In 2012, total extensions and discoveries of 81.5 MMBOE were primarily attributable to successful drilling in the Sanish, Redtail, Missouri Breaks and Pronghorn fields.  The new producing wells in these fields and their related proved undeveloped locations added during the year increased the Company’s proved reserves.
	·                  Revisions to previous estimates.  In 2012, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 7.1 MMBOE.  Included in these revisions were (i) 11.8 MMBOE of downward adjustments caused by lower crude oil and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2012 as compared to December 31, 2011, and (ii) 4.7 MMBOE of net upward adjustments attributable to reservoir analysis and well performance.
	Notable changes in proved reserves for the year ended December 31, 2011 included:
	·                  Extensions and discoveries.  In 2011, total extensions and discoveries of 48.6 MMBOE were primarily attributable to successful drilling in the Sanish and Pronghorn fields.  The new producing wells in these fields and their related proved undeveloped locations added during the year increased the Company’s proved reserves in these areas.
	·                  Revisions to previous estimates.  In 2011, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 19.0 MMBOE.  Included in these revisions were (i) 4.7 MMBOE of upward adjustments caused by higher crude oil prices incorporated into the Company’s reserve estimates at December 31, 2011 as compared to December 31, 2010, and (ii) 14.3 MMBOE of net upward adjustments attributable to reservoir analysis and well performance.  The oil component of the net 14.3 MMBOE revision consisted of a 10.9 MMBOE increase that was primarily related to the Postle and North Ward Estes fields, where the performance of the CO2 injection EOR projects supported an increase in the proved reserve assignments.  The NGL component of the net 14.3 MMBOE revision consisted of a 4.8 MMBOE increase due to the performance of the Postle and North Ward Estes fields and various properties in the Northern Rockies area, primarily in the Sanish field.  The gas component of the net 14.3 MMBOE revision consisted of a 1.4 MMBOE decrease that was primarily related to the Flat Rock field where proved reserve assignments were reduced due to the production performance of two recently completed wells.
	As discussed in Deferred Compensation within these footnotes to the consolidated financial statements, all of the Company’s employees participate in the Company’s Production Participation Plan (the “Plan”).  The reserve disclosures above include oil and natural gas reserve volumes that have been allocated to the Plan.  Once allocated to Plan participants, the interests are fixed.  Allocations prior to 1995 consisted of 2%—3% overriding royalty interest, while allocations since 1995 have been 1.75%—5% of oil and gas sales less lease operating expenses and production taxes from the production allocated to the Plan.
	The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932, Extractive Activities—Oil and Gas.  Future cash inflows as of December 31, 2013, 2012 and 2011 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2013, 2012 and 2011, respectively) to estimated future production.  Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions.
	Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved.  Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves.  Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows.  This calculation does not necessarily result in an estimate of the fair value of the Company’s oil and gas properties.
	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):
		December 31,
		2013			2012			2011
	Future cash flows	$	35,178,399		$	29,308,752		$	26,815,086
	Future production costs	(12,973,292		)	(11,397,332		)	(8,908,131		)
	Future development costs	(5,355,383		)	(3,181,618		)	(1,982,813		)
	Future income tax expense	(3,954,401		)	(4,278,529		)	(4,875,973		)
	Future net cash flows	12,895,323			10,451,273			11,048,169
	10% annual discount for estimated timing of cash flows	(6,301,462		)	(5,044,240		)	(5,775,677		)
	Standardized measure of discounted future net cash flows	$	6,593,861		$	5,407,033		$	5,272,492
	Future cash flows as shown above are reported without consideration for the effects of open hedge contracts at each period end.  If the effects of hedging transactions were included in the computation, then undiscounted future cash inflows would not have changed in 2013 and would have decreased by $20.2 million and $50.7 million in 2012 and 2011, respectively.
	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
		December 31,
		2013			2012			2011
	Beginning of year	$	5,407,033		$	5,272,492		$	3,667,606
	Sale of oil and gas produced, net of production costs	(2,010,925		)	(1,589,665		)	(1,415,469		)
Sales of minerals in place	(1,064,195		)	(438,614		)	(67,600		)
Net changes in prices and production costs	902,916			(1,061,495		)	2,246,014
Extensions, discoveries and improved recoveries	2,827,321			3,708,780			1,156,740
Previously estimated development costs incurred during the period	832,096			526,982			408,079
Changes in estimated future development costs	(1,264,189		)	(1,498,592		)	(797,542		)
Purchases of minerals in place	445,669			—			10,604
Revisions of previous quantity estimates	313,069			(295,432		)	452,668
Net change in income taxes	(335,637		)	255,328			(755,369		)
Accretion of discount	540,703			527,249			366,761
End of year	$	6,593,861		$	5,407,033		$	5,272,492
Future net revenues included in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves incorporate calculated weighted average sales prices (inclusive of adjustments for quality and location) in effect at December 31, 2013, 2012 and 2011 as follows:
	2013			2012			2011
Oil (per Bbl)	$	90.8		$	87.15		$	89.18
NGLs (per Bbl)	$	54.38		$	58.15		$	62.93
Natural Gas (per Mcf)	$	4.3		$	3.21		$	4.39

QUARTERLY_FINANCIAL_DATA_UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2013
QUARTERLY FINANCIAL DATA (UNAUDITED)	'
QUARTERLY FINANCIAL DATA (UNAUDITED)	'
	16.                               QUARTERLY FINANCIAL DATA (UNAUDITED)
	The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2013 and 2012 (in thousands, except per share data):
		Three Months Ended
	Year ended December 31, 2013:	March 31,		June 30,		September 30,		December 31,
		2013		2013		2013		2013
	Oil, NGL and natural gas sales	$	605,114	$	651,868	$	706,543	$	703,024
	Operating profit (1)	$	252,806	$	269,528	$	316,764	$	280,311
	Net income (loss)	$	86,244	$	134,944	$	204,091	$	(59,276	)
	Basic earnings (loss) per share	$	0.73	$	1.14	$	1.72	$	(0.50	)
	Diluted earnings (loss) per share	$	0.72	$	1.14	$	1.71	$	(0.50	)
		Three Months Ended
	Year ended December 31, 2012:	March 31,		June 30,		September 30,		December 31,
		2012		2012		2012		2012
	Oil, NGL and natural gas sales	$	558,697	$	492,756	$	521,195	$	565,066
	Operating profit (1)	$	263,176	$	201,900	$	204,230	$	235,635
	Net income	$	98,446	$	150,851	$	83,113	$	81,689
	Basic earnings per share	$	0.84	$	1.28	$	0.7	$	0.69
	Diluted earnings per share	$	0.83	$	1.27	$	0.7	$	0.69
	(1)               Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.

SCHEDULE_I_CONDENSED_FINANCIAL

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	12 Months Ended
	Dec. 31, 2013
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	'
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	'
	SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
	WHITING PETROLEUM CORPORATION
	CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
	CONDENSED BALANCE SHEETS
	(in thousands)
		December 31,
		2013			2012
	ASSETS
	Current assets	$	5,120		$	2,390
	Investment in subsidiaries	2,707,184			2,330,987
	Intercompany receivable	3,796,321			1,748,463
	Total assets	$	6,508,625		$	4,081,840
	LIABILITIES AND EQUITY
	Current liabilities	$	26,054		$	14,372
	Long-term debt	2,653,834			600,000
	Other long-term liabilities	170			21,244
	Shareholders’ equity	3,828,567			3,446,224
	Total liabilities and equity	$	6,508,625		$	4,081,840
	CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
	(in thousands)
		Year Ended December 31,
		2013			2012			2011
	Operating expenses:
	General and administrative	$	(1,131	)	$	(16,506	)	$	(12,024	)
	Interest expense	(2,922		)	(2,168		)	(2,066		)
	Equity in earnings of subsidiaries	361,732			425,870			500,564
	Income before income taxes	357,679			407,196			486,474
	Income tax benefit	8,376			6,993			5,213
	Net income	$	366,055		$	414,189		$	491,687
	Comprehensive income	$	366,055		$	414,189		$	491,687
	See notes to condensed financial statements.
	CONDENSED STATEMENTS OF CASH FLOWS
	(in thousands)
		Year Ended December 31,
		2013			2012			2011
	Cash flows provided by operating activities	$	—		$	16,423		$	4,962
	Cash flows from investing activities:
	Investment in subsidiaries	—			—			—
	Cash flows from financing activities:
	Intercompany receivable	(2,048,253		)	(14,094		)	(3,091		)
	Issuance of 5% Senior Notes due 2019	1,100,000			—			—
	Issuance of 5.75% Senior Notes due 2021	1,204,000			—			—
	Redemption of 7% Senior Subordinated Notes due 2014	(253,988		)	—			—
	Other financing activities	(1,759		)	(2,329		)	(1,871		)
	Net cash used in financing activities	—			(16,423		)	(4,962		)
	Net change in cash and cash equivalents	—			—			—
	Cash and cash equivalents:
	Beginning of period	—			—			—
	End of period	$	—		$	—		$	—
	NONCASH INVESTING ACTIVITIES:
	Distributions from Whiting USA Trust I decreasing investment in subsidiaries	$	(4,749	)	$	(5,827	)	$	(6,500	)
	See notes to condensed financial statements.					(Continued)
	CONDENSED STATEMENTS OF CASH FLOWS
	(in thousands)
		Year Ended December 31,
		2013			2012			2011
	NONCASH FINANCING ACTIVITIES:
	Preferred stock dividends paid decreasing shareholders’ equity	$	(538	)	$	(1,077	)	$	(1,077	)
	Preferred stock dividends paid decreasing intercompany receivable	$	(538	)	$	(1,077	)	$	(1,077	)
	Distributions from Whiting USA Trust I increasing intercompany receivable	$	4,749		$	5,827		$	6,500
	See notes to condensed financial statements.					(Concluded)
	WHITING PETROLEUM CORPORATION
	NOTES TO CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
1.             BASIS OF PRESENTATION
Condensed Financial Statements—The condensed financial statements of Whiting Petroleum Corporation (the “Registrant” or “Parent Company”) do not include all of the information and notes normally included with financial statements prepared in accordance with GAAP.  These condensed financial statements, therefore, should be read in conjunction with the consolidated financial statements and notes thereto of the Registrant, included elsewhere in this Annual Report on Form 10-K.  For purposes of these condensed financial statements, the Parent Company’s investments in wholly-owned subsidiaries are accounted for under the equity method.
Restricted Assets of Registrant—Except for limited exceptions, including the payment of interest on the senior notes and senior subordinated notes, Whiting Oil and Gas Corporation’s (“Whiting Oil and Gas”) credit agreement restricts the ability of Whiting Oil and Gas to make any dividend payments, distributions or other payments to the Parent Company.  As of December 31, 2013, total restricted net assets were $4,070.4 million.  Accordingly, these condensed financial statements have been prepared pursuant to Rule 5-04 of Regulation S-X of the Securities Exchange Act of 1934, as amended.
2.             LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
The Parent Company’s long-term debt and other long-term liabilities consisted of the following at December 31, 2013 and 2012 (in thousands):
	December 31,
	2013			2012
Long-term debt:
7% Senior Subordinated Notes due 2014	$	—		$	250,000
6.5% Senior Subordinated Notes due 2018	350,000			350,000
5% Senior Notes due 2019	1,100,000			—
5.75% Senior Notes due 2021, including unamortized debt premium of $3,834	1,203,834			—
Other long-term liabilities:
Tax sharing liability (1)	—			21,074
Other	170			170
Total long-term debt and other long-term liabilities	$	2,654,004		$	621,244
(1)         As of December 31, 2013, the entire $23.9 million balance due to Alliant Energy under the tax sharing agreement was reflected as a current liability in these condensed financial statements and is included in the schedule of maturities below.
Scheduled maturities of the Parent Company’s principal amounts of long-term debt and other long-term liabilities (including the current portions thereof) as of December 31, 2013 were as follows (in thousands):
	2014			2015			2016			2017		2018		Thereafter		Total
Amounts due	$	23,856		$	—		$	—		$	—	$	350,000	$	2,300,000	$	2,673,856
For further information on the Senior Subordinated Notes, Senior Notes and tax sharing liability, refer to the Long-Term Debt and Related Party Transactions notes to the consolidated financial statements of the Registrant.
3.             SHAREHOLDERS’ EQUITY
Common Stock—In May 2011, the Registrant’s stockholders approved an amendment to its Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 175,000,000 shares to 300,000,000 shares.
Stock Split.  On January 26, 2011, the Board of Directors approved a two-for-one split of the Registrant’s shares of common stock to be effected in the form of a stock dividend.  As a result of the stock split, stockholders of record on February 7, 2011 received one additional share of common stock for each share of common stock held. The additional shares of common stock were distributed on February 22, 2011.  The common stock dividend resulted in the conversion price for Parent Company’s 6.25% Convertible Perpetual Preferred Stock being adjusted from $43.4163 to $21.70815.
6.25% Convertible Perpetual Preferred Stock—In June 2009, the Parent Company completed a public offering of 6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a price of $100.00 per share.  As a result of voluntary conversions and the Parent Company exercising its right to mandatorily convert shares of preferred stock effective June 27, 2013, all 172,129 shares of preferred stock outstanding on March 31, 2013, were converted into 792,919 shares of common stock.  As of December 31, 2013, no shares of preferred stock remained outstanding.
For further information on the common stock and convertible perpetual preferred stock, refer to the Shareholders’ Equity note to the consolidated financial statements of the Registrant.

SUMMARY_OF_SIGNIFICANT_ACCOUNT1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2013
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
Basis of Presentation of Consolidated Financial Statements	'
	Basis of Presentation of Consolidated Financial Statements—The consolidated financial statements include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s 15.8% ownership interest in Trust I.  Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method.  Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses.  All intercompany balances and transactions have been eliminated upon consolidation.
Use of Estimates	'
	Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  Items subject to such estimates and assumptions include (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) income taxes; (7) Production Participation Plan and other accrued liabilities; (8) valuation of derivative instruments; and (9) accrued revenue and related receivables.  Although management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents—Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.
Accounts Receivable Trade	'
	Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates.  For receivables from joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.  Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts.
	The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability.  At December 31, 2013 and 2012, the Company had an allowance for doubtful accounts of $4.2 million and $3.9 million, respectively.
Inventories	'
	Inventories—Materials and supplies inventories consist primarily of tubular goods and production equipment, carried at weighted-average cost.  Materials and supplies are included in other property and equipment.  Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or market value and is included in prepaid expenses and other.
Oil and Gas Properties	'
	Oil and Gas Properties
	Proved.  The Company follows the successful efforts method of accounting for its oil and gas properties.  Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.  Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.
	The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable.  The impairment test compares undiscounted future net cash flows to the assets’ net book value.  If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value.  Fair value for oil and gas properties is generally determined based on discounted future net cash flows.  Impairment expense for proved properties is reported in exploration and impairment expense.
	Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income.  Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.
	Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use.  During 2013, 2012 and 2011, the Company capitalized interest of $1.5 million, $2.7 million and $3.6 million, respectively.
	Unproved.  Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves.  Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on past success, past experience and average lease-term lives.  The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.  When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis.  Impairment expense for unproved properties is reported in exploration and impairment expense.
	Exploratory.  Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred.  Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs.  Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations.  To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
	Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves.  If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense.  Cost incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.  If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.
	Enhanced recovery activities.  The Company carries out tertiary recovery methods on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods.  Acquisition costs of tertiary injectants, such as purchased CO2, for enhanced oil recovery (“EOR”) activities that are used during a project’s pilot phase, or prior to a project’s technical and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as incurred.  After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project.  As CO2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO2 recycling costs are expensed as incurred.  Likewise costs incurred to maintain reservoir pressure are also expensed.
	Other Property and Equipment—Other property and equipment consists of (i) materials and supplies inventories, (ii) leasehold costs and development costs of our CO2 source properties and (iii) other property and equipment including an oil pipeline, 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 33 years.  In July 2013, the Company sold the oil pipeline, as discussed in the Acquisitions and Divestitures footnote.
Debt Issuance Costs	'
	Debt Issuance Costs—Debt issuance costs related to the Company’s Senior Notes and Senior Subordinated Notes 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 amortized to interest expense on a straight-line basis over the borrowing term.
Asset Retirement Obligations and Environmental Costs	'
	Asset Retirement Obligations and Environmental Costs—Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or 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 units-of-production basis over the proved developed reserves of the related asset.  Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability.
	Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that obligations have been incurred and the amounts can be reasonably estimated.  These liabilities are not reduced by possible recoveries from third parties.
Derivative Instruments	'
	Derivative Instruments—The Company enters into derivative contracts, primarily costless collars, to manage its exposure to commodity price risk.  All derivative instruments, other than those that meet the “normal purchase normal sales” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value.  Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria, and the derivative has been designated as a hedge.  Effective April 1, 2009, however, the Company elected to discontinue all hedge accounting prospectively.  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.
	For derivatives qualifying as hedges of future cash flows prior to April 1, 2009, the effective portion of any changes in fair value was recognized in accumulated other comprehensive income (loss) and was reclassified to net income when the underlying forecasted transaction occurred.  Any ineffective portion of such hedges was recognized in commodity derivative (gain) loss, net as it occurred.  For discontinued cash flow hedges, prospective changes in the fair value of the derivative are recognized in earnings.  The accumulated gain or loss recognized in accumulated other comprehensive income (loss) at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs.  However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in accumulated other comprehensive income (loss) is immediately reclassified into earnings.  As of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings.
Deferred Gain on Sales	'
	Deferred Gain on Sale—The deferred gain on sale relates to the sale of 11,677,500 Trust I units and 18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the units-of-production method.
Revenue Recognition	'
	Revenue Recognition—Oil and gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, persuasive evidence of a sales arrangement exists and collectability of the revenue is probable.  Revenues from the production of gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest (entitlement method).  Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as receivables.  Gas imbalance receivables or payables are valued at the lowest of (i) the current market price, (ii) the price in effect at the time of production, or (iii) the contract price, if a contract is in hand.  As of December 31, 2013 and 2012, the Company was in a net under (over) produced imbalance position of (110,798) Mcf and (53,536) Mcf, respectively.
	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 working interest owners in the oil and gas properties operated by Whiting.
Acquisition Costs	'
	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 which do not extend the useful lives of property and equipment are charged to expense as incurred.  Major replacements, renewals and betterments are capitalized.
Income Taxes	'
	Income Taxes—Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes.  Deferred income taxes are accounted for using the liability method.  Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.  The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense.
Earnings Per Share	'
	Earnings Per Share—Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period.  Diluted earnings per common share is calculated by dividing adjusted net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options using the treasury method, as well as convertible perpetual preferred stock using the if-converted method.  In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized.  When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.
Industry Segment and Geographic Information	'
	Industry Segment and Geographic Information—The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, NGLs and natural gas.  The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities.  All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments—The Company has included fair value information in these notes when the fair value of our financial instruments is materially different from their book value.  Cash and cash equivalents, accounts receivable and payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments.  The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates.  The Company’s Senior Notes and Senior Subordinated Notes are recorded at cost, and the fair values of these instruments are included in the Long-Term Debt footnote.  The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate.
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 table presents the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2013, 2012 and 2011:
		2013		2012		2011
	Plains Marketing LP	21	%	20	%	27	%
	Shell Trading US	14	%	14	%	13	%
	Eighty Eight Oil Company	11	%	11	%	8	%
	Bridger Trading LLC	8	%	11	%	6	%
	Commodity derivative contracts held by the Company are with eight counterparties, all of which are participants in Whiting’s credit facility as well, and all of which have investment-grade ratings from Moody’s and Standard & Poor.  As of December 31, 2013, outstanding derivative contracts with JP Morgan Chase Bank, N.A., Canadian Imperial Bank of Commerce, The Bank of Nova Scotia and Bank of America Merrill Lynch represented 29%, 21%, 12% and 12%, respectively, of total crude oil volumes hedged.
Reclassifications	'
	Reclassifications—Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current year presentation.  Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
Adopted and Recently Issued Accounting Pronouncements	'
	Adopted and Recently IssuedAccounting Pronouncements—In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which provides amendments to FASB ASC Topic 820, Fair Value Measurement.  The objective of ASU 2011-04 is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”).  The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements.  ASU 2011-04 was effective for interim and annual reporting periods beginning after December 15, 2011.  The Company adopted this standard effective January 1, 2012, which did not have an impact on the Company’s consolidated financial statements other than additional disclosures.
	In June 2011, the FASB issued Accounting Standards Update No. 2011-05, Comprehensive Income: Presentation of Comprehensive Income (“ASU 2011-05”), which provides amendments to FASB ASC Topic 220, Comprehensive Income.  The objective of ASU 2011-05 is to require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements.  ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of equity.  ASU 2011-05 is effective for interim and annual periods beginning after December 15, 2011 and is to be applied retrospectively.  In December 2011, the FASB issued Accounting Standards Update No. 2011-12, Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which deferred the effective date of changes in ASU 2011-05 that relate to the presentation of reclassification adjustments out of accumulated other comprehensive income.  The amendments in this update are effective at the same time as the amendments in ASU 2011-05.  The Company adopted the provisions of ASU 2011-05 and 2011-12 effective January 1, 2012, which did not have an impact on its consolidated financial statements other than requiring the Company to present its statements of comprehensive income separately from its statements of equity, as these statements were formerly presented on a combined basis.
	In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”).  The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position.  In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with FASB ASC Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities lending transactions that are either offset in accordance with FASB ASC Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement.  ASU 2011-11 and ASU 2013-01 are effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively.  The Company adopted ASU 2011-11 and ASU 2013-01 effective January 1, 2013, which did not have an impact on the Company’s consolidated financial statements other than additional disclosures.
	In July 2012, the FASB issued Accounting Standards Update No. 2012-02, Intangibles — Goodwill and Other — Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”).  The objective of ASU 2012-02 is to reduce the cost and complexity of performing an impairment test for indefinite-lived intangible assets by permitting an entity first to assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired, as a basis for determining whether it is necessary to perform a quantitative impairment test.  ASU 2012-02 is effective for interim and annual reporting periods beginning after September 15, 2012.  The Company adopted ASU 2012-02 effective January 1, 2013, which did not have an impact on the Company’s consolidated financial statements.
	In February 2013, the FASB issued Accounting Standards Update No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”).  The objective of ASU 2013-02 is to improve the reporting of reclassifications out of AOCI by requiring an entity to report the effect of significant reclassifications out of AOCI on the respective line items in net income if the amount being reclassified is required under GAAP to be reclassified in its entirety to net income.  For other amounts that are not required under GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under GAAP that provide additional detail about those amounts.  ASU 2013-02 is effective for interim and annual reporting periods beginning after December 15, 2012.  The Company adopted ASU 2013-02 effective January 1, 2013, which did not have a significant impact on the Company’s consolidated financial statements.
	In February 2013, the FASB issued Accounting Standards Update No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“ASU 2013-04”).  The objective of ASU 2013-04 is to provide guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date.  ASU 2013-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.  The adoption of this standard will not have an impact on the Company’s consolidated financial statements.
	In July 2013, the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”).  The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists.  ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.  The adoption of this standard will not have an impact on the Company’s consolidated financial statements, other than insignificant balance sheet reclassifications.

SUMMARY_OF_SIGNIFICANT_ACCOUNT2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2013
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
Percentages of total oil and gas sales to significant purchasers	'
		2013		2012		2011
	Plains Marketing LP	21	%	20	%	27	%
	Shell Trading US	14	%	14	%	13	%
	Eighty Eight Oil Company	11	%	11	%	8	%
	Bridger Trading LLC	8	%	11	%	6	%

OIL_AND_GAS_PROPERTIES_Tables

OIL AND GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2013
OIL AND GAS PROPERTIES	'
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, 2013 and 2012 are as follows (in thousands):
		December 31,
		2013			2012
	Proved leasehold costs	$	1,633,495		$	2,119,541
	Unproved leasehold costs	372,298			362,483
	Costs of completed wells and facilities	7,563,350			6,369,170
	Wells and facilities in progress	496,007			360,804
	Total oil and gas properties, successful efforts method	10,065,150			9,211,998
	Accumulated depletion	(2,645,841		)	(2,564,081		)
	Oil and gas properties, net	$	7,419,309		$	6,647,917

ACQUISITIONS_AND_DIVESTITURES_

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2013
ACQUISITIONS AND DIVESTITURES	'
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):
	Purchase price	$	258,892
	Allocation of purchase price:
	Proved properties	$	232,187
	Unproved properties	27,335
	Oil in tank inventory	692
	Accounts receivable	578
	Asset retirement obligations	(1,900		)
	Total	$	258,892
Schedule of crude oil swaps and any of the related cash settlements transferred to the buyer of the Postle Properties	'
	Period	Contracted Crude Oil Volumes		NYMEX Price for Crude Oil
		(Bbl)		(per Bbl)
	Apr – Dec 2013	1,677,500		$	98.5
	Jan – Dec 2014	2,007,500		$	94.75
	Jan – Dec 2015	1,825,000		$	94.75
	Jan – Mar 2016	400,400		$	93.5
	Total	5,910,400

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2013
LONG-TERM DEBT	'
Schedule of long-term debt	'
	Long-term debt consisted of the following at December 31, 2013 and 2012 (in thousands):
		December 31,
		2013			2012
	Credit agreement	$	—		$	1,200,000
	7% Senior Subordinated Notes due 2014	—			250,000
	6.5% Senior Subordinated Notes due 2018	350,000			350,000
	5% Senior Notes due 2019	1,100,000			—
	5.75% Senior Notes due 2021, including unamortized debt premium of $3,834	1,203,834			—
	Total debt	$	2,653,834		$	1,800,000
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 scheduled maturities for the Company’s long-term debt as of December 31, 2013 (in thousands):
		2014			2015			2016		2017		2018
	Long-term debt	$	—		$	—		$	—	$	—	$	350,000
Summary of margin rates and commitment fees	'
	Ratio of Outstanding Borrowings to Borrowing Base	Applicable		Applicable		Commitment
		Margin for Base		Margin for		Fee
		Rate Loans		Eurodollar Loans
	Less than 0.25 to 1.0	0.5	%	1.5	%	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	%	2	%	0.5	%
	Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0	1.25	%	2.25	%	0.5	%
	Greater than or equal to 0.90 to 1.0	1.5	%	2.5	%	0.5	%

ASSET_RETIREMENT_OBLIGATIONS_T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2013
ASSET RETIREMENT OBLIGATIONS	'
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 year ended December 31, 2013 and 2012 (in thousands):
		Year Ended December 31,
		2013			2012
	Asset retirement obligation at January 1	$	97,818		$	69,721
	Additional liability incurred	17,535			9,292
	Revisions in estimated cash flows	12,225			23,162
	Accretion expense	10,608			7,263
	Obligations on sold properties	(3,630		)	(4		)
	Liabilities settled	(8,408		)	(11,616		)
	Asset retirement obligation at December 31	$	126,148		$	97,818

DERIVATIVE_FINANCIAL_INSTRUMEN1

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Financial Instruments	'
Schedule of effects of commodity derivative instruments	'
	The following tables summarize the effects of commodity derivative instruments on the consolidated statements of income for the year ended December 31, 2013 and 2012 (in thousands):
			Gain (Loss) Reclassified from AOCI
			into Income (Effective Portion) (1)
	ASC 815 Cash Flow		Year Ended December 31,
	Hedging Relationships (1)	Income Statement Classification	2013			2012
	Commodity contracts	Gain (loss) on hedging activities	$	(1,958	)	$	2,338
	(1)               Effective April 1, 2009, the Company elected to de-designate all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively.  As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were being reclassified into earnings as the original hedged transactions affected income.  As of December 31, 2013, all amounts had been reclassified into earnings.
			(Gain) Loss Recognized in Income
	Not Designated as		Year Ended December 31,
	ASC 815 Hedges	Income Statement Classification	2013			2012
	Commodity contracts	Commodity derivative (gain) loss, net	$	20,503		$	(75,782	)
	Embedded commodity contracts	Commodity derivative (gain) loss, net	(12,701		)	(10,129		)
	Total		$	7,802		$	(85,911	)
Location and fair value of derivative instruments	'
	The following tables summarize the location and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands):
			December 31, 2013(1)
	Not Designated as	Balance Sheet Classification	Gross			Gross			Net
	ASC 815 Hedges		Recognized			Amounts			Recognized
			Assets/			Offset			Fair Value
			Liabilities						Assets/
									Liabilities
	Derivative assets:
	Commodity contracts	Prepaid expenses and other	$	23,752		$	(22,478	)	$	1,274
	Embedded commodity contracts	Other long-term assets	36,416			—			36,416
	Total derivative assets		$	60,168		$	(22,478	)	$	37,690
	Derivative liabilities:
	Commodity contracts	Current derivative liabilities	$	25,960		$	(22,478	)	$	3,482
	Total derivative liabilities		$	25,960		$	(22,478	)	$	3,482
			December 31, 2012(1)
	Not Designated as	Balance Sheet Classification	Gross			Gross			Net
	ASC 815 Hedges		Recognized			Amounts			Recognized
			Assets/			Offset			Fair Value
			Liabilities						Assets/
									Liabilities
	Derivative assets:
	Commodity contracts	Prepaid expenses and other	$	40,909		$	(31,437	)	$	9,472
	Commodity contracts	Other long-term assets	4,053			(2,189		)	1,864
	Embedded commodity contracts	Other long-term assets	24,038			(323		)	23,715
	Total derivative assets		$	69,000		$	(33,949	)	$	35,051
	Derivative liabilities:
	Commodity contracts	Current derivative liabilities	$	53,392		$	(31,437	)	$	21,955
	Commodity contracts	Non-current derivative liabilities	3,867			(2,189		)	1,678
	Embedded commodity contracts	Non-current derivative liabilities	323			(323		)	—
	Total derivative liabilities		$	57,582		$	(33,949	)	$	23,633
	(1)               Because counterparties to the Company’s derivative contracts are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above.
Whiting Petroleum Corporation	'
Derivative Financial Instruments	'
Derivative instruments	'
	The table below details the Company’s costless collar derivatives, including its proportionate share of Trust II derivatives, entered into to hedge forecasted crude oil production revenues, as of February 6, 2014.
			Whiting Petroleum Corporation
	Derivative	Period	Contracted Crude Oil		Weighted Average NYMEX Price
	Instrument		Volumes (Bbl)		Collar Ranges for Crude Oil (per Bbl)
	Collars	Jan – Dec 2014	49,290		$ 80.00 - $122.50
	Three-way collars(1)	Jan – Dec 2014	15,280,000		$70.94 - $85.00 - $103.35
		Total	15,329,290
	(1)               A three-way collar is a combination of options: a sold call, a purchased put and a sold put.  The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract.  The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.
Whiting USA Trust II Units	'
Derivative Financial Instruments	'
Derivative instruments	'
			Whiting Petroleum Corporation
	Derivative	Period	Contracted Crude Oil		NYMEX Price Collar Ranges for
	Instrument		Volumes (Bbl)		Crude Oil (per Bbl)
	Collars	Jan – Dec 2014	49,290		$80.00 - $122.50
Third party public holders of Whiting USA Trust II	'
Derivative Financial Instruments	'
Derivative instruments	'
			Third-party Public Holders of Trust II Units
	Derivative	Period	Contracted Crude Oil		NYMEX Price Collar Ranges for
	Instrument		Volumes (Bbl)		Crude Oil (per Bbl)
	Collars	Jan – Dec 2014	443,610		$80.00 - $122.50

FAIR_VALUE_MEASUREMENTS_Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2013
FAIR VALUE MEASUREMENTS	'
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, 2013 and 2012, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):
		Level 1		Level 2			Level 3		Total Fair Value
									December 31,
									2013
	Financial Assets
	Commodity derivatives – current	$	—	$	1,274		$	—	$	1,274
	Embedded commodity derivatives – non-current	—		—			36,416		36,416
	Total financial assets	$	—	$	1,274		$	36,416	$	37,690
	Financial Liabilities
	Commodity derivatives – current	$	—	$	3,482		$	—	$	3,482
	Total financial liabilities	$	—	$	3,482		$	—	$	3,482
		Level 1		Level 2			Level 3		Total Fair Value
									December 31,
									2012
	Financial Assets
	Commodity derivatives – current	$	—	$	9,472		$	—	$	9,472
	Commodity derivatives – non-current	—		1,864			—		1,864
	Embedded commodity derivatives – non-current	—		—			23,715		23,715
	Total financial assets	$	—	$	11,336		$	23,715	$	35,051
	Financial Liabilities
	Commodity derivatives – current	$	—	$	21,955		$	—	$	21,955
	Commodity derivatives – non-current	—		1,678			—		1,678
	Total financial liabilities	$	—	$	23,633		$	—	$	23,633
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 (liabilities) designated as Level 3 in the valuation hierarchy for the year ended December 31, 2013 and 2012 (in thousands):
		Year Ended December 31,
		2013		2012
	Fair value asset, beginning of period	$	23,715	$	12,980
	Unrealized gains (losses) on embedded commodity derivative contracts included in earnings(1)	12,701		10,735
	Transfers into (out of) Level 3	—		—
	Fair value asset, end of period	$	36,416	$	23,715
	(1)               Included in commodity derivative (gain) loss, net in the consolidated statements of income.
Significant unobservable inputs used in the fair value measurement	'
		Fair Value at		Valuation		Unobservable		Range
		December 31, 2013		Technique		Input		(per Bbl)
		(in thousands)
	Embedded commodity derivative	$	36,416	Option model		Future prices of		$ 79.87 - $95.75
						NYMEX crude oil after
						March 31, 2022
Non-financial assets and liabilities measured at fair value on a nonrecurring basis	'
	The following tables present information about the Company’s non-financial assets and liabilities measured at fair value on a nonrecurring basis as of December 31, 2013 and 2012, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):
		Net Carrying		Fair Value Measurements Using							Loss (Before
		Value as of									Tax) Year
		December 31,									Ended
											December 31,
		2013		Level 1			Level 2		Level 3		2013
	Proved property impairments(1)	$	106,114	$	—		$	—	$	106,114	$	267,109
	(1)               During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373.2 million were written down to their fair value of $106.1 million, resulting in a non-cash impairment charge of $267.1 million.  The impairment consisted of (i) a $220.8 million write-down in the Rocky Mountains region and Michigan related to the decrease in the forward price curve for natural gas at December 31, 2013 and the associated decline in gas reserves in those areas and (ii) a $46.3 million write-down in the Rocky Mountains region related to well performance and associated changes in reserves during the fourth quarter of 2013.
		Net Carrying		Fair Value Measurements Using							Loss (Before
		Value as of									Tax) Year
		December 31,									Ended
											December 31,
		2012		Level 1			Level 2		Level 3		2012
	Proved property impairments(1)	$	23,473	$	—		$	—	$	23,473	$	46,924
	(1)               During the year ended December 31, 2012, proved oil and gas properties with a carrying amount of $70.4 million were written down to their fair value of $23.5 million, resulting in a non-cash impairment charge of $46.9 million.  The impairment consisted primarily of a $46.3 million write-down in the Rocky Mountains region related to changes in estimated reserves at December 31, 2012.

DEFERRED_COMPENSATION_Tables

DEFERRED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2013
DEFERRED COMPENSATION	'
Schedule of changes in the plan's estimated long-term liability	'
	The following table presents changes in the Plan’s estimated long-term liability (in thousands):
		Year Ended December 31,
		2013			2012
	Long-term Production Participation Plan liability at January 1	$	94,483		$	80,659
	Change in liability for accretion, vesting, changes in estimates and new Plan year activity	66,284			63,135
	Accrued compensation expense reflected as a current liability	(73,264		)	(49,311		)
	Long-term Production Participation Plan liability at December 31	$	87,503		$	94,483

SHAREHOLDERS_EQUITY_AND_NONCON1

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Tables)	12 Months Ended
	Dec. 31, 2013
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST	'
Assumption for valuing market based restricted shares	'
		2013		2012		2011
	Number of simulations	65,000		65,000		65,000
	Expected volatility	43.1	%	51.9	%	75.8	%
	Risk-free rate	0.41	%	0.35	%	1	%
	Dividend yield	—		—		—
Summary of nonvested restricted stock	'
		Number		Weighted Average
		of Shares		Grant Date
				Fair Value
	Restricted stock awards nonvested, January 1, 2011	869,370		$	16.27
	Granted	304,355		48.48
	Vested	(429,136	)	15.32
	Forfeited	(20,194	)	33.53
	Restricted stock awards nonvested, December 31, 2011	724,395		29.88
	Granted	592,400		34.45
	Vested	(357,170	)	17.91
	Forfeited	(8,599	)	51.72
	Restricted stock awards nonvested, December 31, 2012	951,026		37.02
	Granted	940,792		27.59
	Vested	(347,824	)	35.32
	Forfeited	(99,684	)	30.95
	Restricted stock awards nonvested, December 31, 2013	1,444,310		$	31.71
Assumptions used to estimate the grant date fair value of stock options awarded	'
		2012		2011
	Risk-free interest rate	1.19	%	2.47	%
	Expected volatility	61.4	%	59.3	%
	Expected term	6.0 yrs.		6.0 yrs.
	Dividend yield	—		—
Summary of stock options outstanding	'
		Number of		Weighted			Aggregate		Weighted
		Options		Average			Intrinsic		Average
				Exercise Price			Value		Remaining
				per Share			(in thousands)		Contractual
									Term
									(in years)
	Options outstanding at January 1, 2011	296,516		$	16.78
	Granted	80,820		60.28
	Exercised	—		—			$	—
	Forfeited or expired	—		—
	Options outstanding at December 31, 2011	377,336		26.09
	Granted	45,359		51.22
	Exercised	—		—			$	—
	Forfeited or expired	—		—
	Options outstanding at December 31, 2012	422,695		28.79
	Granted	—		—
	Exercised	—		—			$	—
	Forfeited or expired	(1,855	)	60.28
	Options outstanding at December 31, 2013	420,840		$	28.65		$	13,979.60	5.9
	Options vested and expected to vest at December 31, 2013	420,840		$	28.65		$	13,979.60	5.9
	Options exercisable at December 31, 2013	365,511		$	24.61		$	13,617.80	5.7
Schedule of noncontrolling interest	'
	The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):
		Year Ended December 31,
		2013			2012
	Balance at January 1	$	8,184		$	8,274
	Net income (loss)	(52		)	(90		)
	Balance at December 31	$	8,132		$	8,184

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2013
INCOME TAXES	'
Schedule of income tax expense	'
	Income tax expense consists of the following (in thousands):
		Year Ended December 31,
		2013			2012			2011
	Current income tax expense (refund):
	Federal	$	7,060		$	—		$	107
	State	(6,074		)	(669		)	3,746
	Total current income tax expense	986			(669		)	3,853
	Deferred income tax expense:
	Federal	196,787			233,468			272,653
	State	8,095			15,113			12,185
	Total deferred income tax expense	204,882			248,581			284,838
	Total	$	205,868		$	247,912		$	288,691
Reconciliation of statutory income tax expense to income tax expense	'
	Income tax expense differed from amounts that would result from applying the U.S. statutory income tax rate (35%) to income before income taxes as follows (in thousands):
		Year Ended December 31,
		2013			2012			2011
	U.S. statutory income tax expense	$	200,155		$	231,704		$	273,112
	State income taxes, net of federal benefit	13,962			14,444			16,602
	State income tax credits	(10,525		)	—			—
	Statutory depletion	(796		)	(620		)	(697		)
	Enacted changes in state tax laws	(1,416		)	—			(1,842		)
	Permanent items	2,122			1,524			1,420
	Other	2,366			860			96
	Total	$	205,868		$	247,912		$	288,691
Components of deferred income tax assets and liabilities	'
	The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2013 and 2012 were as follows (in thousands):
		Year Ended December 31,
		2013			2012
	Deferred income tax assets:
	Net operating loss carryforward	$	438,922		$	520,980
	Derivative instruments	—			19,957
	Production Participation Plan liability	32,245			34,865
	Tax sharing liability	9,439			8,312
	Asset retirement obligations	23,642			19,759
	Underwriter fees	10,974			12,677
	Restricted stock compensation	13,384			9,852
	Enhanced oil recovery credit carryforwards	7,946			7,946
	Alternative minimum tax credit carryforwards	18,452			11,391
	Foreign tax credit carryforwards	1,230			1,230
	Other	2,004			1,508
	Total deferred income tax assets	558,238			648,477
	Less valuation allowances	(1,230		)	(1,230		)
	Net deferred income tax assets	557,008			647,247
	Deferred income tax liabilities:
	Oil and gas properties	1,675,916			1,555,142
	Trust distributions	149,332			165,180
	Derivative instruments	10,438			—
	Total deferred income tax liabilities	1,835,686			1,720,322
	Total net deferred income tax liabilities	$	1,278,678		$	1,073,075
Net deferred income tax liabilities	'
	Net deferred income tax liabilities were classified in the consolidated balance sheets as follows (in thousands):
		Year Ended December 31,
		2013			2012
	Assets:
	Current deferred income taxes	$	—		$	—
	Liabilities:
	Current deferred income taxes	648			9,394
	Non-current deferred income taxes	1,278,030			1,063,681
	Net deferred income tax liabilities	$	1,278,678		$	1,073,075
Liability for unrecognized tax benefits	'
	The following table summarizes the activity related to the Company’s liability for unrecognized tax benefits (in thousands):
		Year Ended December 31,
		2013			2012			2011
	Beginning balance at January 1	$	170		$	299		$	299
	Decrease related to tax position taken in a prior period	—			(129		)	—
	Ending balance at December 31	$	170		$	170		$	299

EARNINGS_PER_SHARE_Tables

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2013
EARNINGS PER SHARE	'
Reconciliations between basic and diluted earnings per share	'
	The reconciliations between basic and diluted earnings per share are as follows (in thousands, except per share data):
		Year Ended December 31,
		2013			2012			2011
	Basic Earnings Per Share
	Numerator:
	Net income available to shareholders	$	366,055		$	414,189		$	491,687
	Preferred stock dividends (1)	(494		)	(1,077		)	(1,077		)
	Net income available to common shareholders, basic	$	365,561		$	413,112		$	490,610
	Denominator:
	Weighted average shares outstanding, basic	118,260			117,601			117,345
	Diluted Earnings Per Share
	Numerator:
	Net income available to common shareholders, basic	$	365,561		$	413,112		$	490,610
	Preferred stock dividends	538			1,077			1,077
	Adjusted net income available to common shareholders, diluted	$	366,099		$	414,189		$	491,687
	Denominator:
	Weighted average shares outstanding, basic	118,260			117,601			117,345
	Restricted stock and stock options	957			633			529
	Convertible perpetual preferred stock	371			794			794
	Weighted average shares outstanding, diluted	119,588			119,028			118,668
	Earnings per common share, basic	$	3.09		$	3.51		$	4.18
	Earnings per common share, diluted	$	3.06		$	3.48		$	4.14
	(1)               For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated.  There were no accumulated dividend adjustments for the years ended December 31, 2012 and 2011.

RELATED_PARTY_TRANSACTIONS_Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2013
RELATED PARTY TRANSACTIONS	'
Summary of related party receivable and payable balances	'
	The following table summarizes the related party receivable and payable balances between the Company and Trust I as of December 31, 2013 and 2012 (in thousands):
		December 31,
		2013		2012
	Assets
	Unit distributions due from Trust I (1)	$	1,093	$	929
	Liabilities
	Unit distributions payable to Trust I (2)	$	6,932	$	5,731
	(1)               This amount represents Whiting’s 15.8% interest in the net proceeds due from Trust I and is included within accounts receivable trade, net in the Company’s consolidated balance sheets.
	(2)               This amount represents net proceeds from Trust I’s underlying properties that the Company has received between the last Trust I distribution date and December 31, 2013 and 2012, respectively, but which the Company has not yet distributed to Trust I as of December 31, 2013 and 2012, respectively.  Due to ongoing processing of Trust I revenues and expenses after December 31, 2013 and 2012, the amount of Whiting’s next scheduled distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this amount.  These amounts are included within accounts payable trade in the Company’s consolidated balance sheet.

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2013
COMMITMENTS AND CONTINGENCIES	'
Schedule of the Company's 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 operating leases and unconditional purchase obligations as of December 31, 2013 (in thousands):
		Payments due by period
		2014		2015		2016		2017		2018		Thereafter		Total
	Non-cancelable leases	$	6,279	$	5,872	$	5,387	$	5,250	$	4,629	$	1,374	$	28,791
	Drilling rig contracts	87,610		48,531		1,755		—		—		—		137,896
	Construction and drilling contract	31,066		—		2,900		6,900		4,100		—		44,966
	Total	$	124,955	$	54,403	$	10,042	$	12,150	$	8,729	$	1,374	$	211,653

OIL_AND_GAS_ACTIVITIES_Tables

OIL AND GAS ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2013
OIL AND GAS ACTIVITIES	'
Schedule of cost Incurred in oil and gas producing activities	'
	Costs incurred in oil and gas producing activities were as follows (in thousands):
		Year Ended December 31,
		2013			2012			2011
	Development(1)	$	2,132,824		$	1,667,182		$	1,245,150
	Proved property acquisition	232,572			19,785			4,324
	Unproved property acquisition	174,103			119,175			191,482
	Exploration	363,234			436,084			400,823
	Total	$	2,902,733		$	2,242,226		$	1,841,779
	(1)               During 2013, 2012 and 2011, non-cash additions to oil and gas properties of $29.8 million, $36.3 million and $4.9 million, respectively, which relate to estimated costs of the future plugging and abandonment of the
Net changes in capitalized exploratory well costs	'
	The net changes in capitalized exploratory well costs were as follows (in thousands):
		Year Ended December 31,
		2013			2012			2011
	Beginning balance at January 1	$	108,861		$	90,519		$	4,434
	Additions to capitalized exploratory well costs pending the determination of proved reserves	281,951			384,223			354,962
	Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(291,962		)	(358,625		)	(267,847		)
	Capitalized exploratory well costs charged to expense	(13,472		)	(7,256		)	(1,030		)
	Ending balance at December 31	$	85,378		$	108,861		$	90,519

DISCLOSURES_ABOUT_OIL_AND_GAS_1

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2013
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	'
Summary of changes in quantities of proved oil and gas reserve	'
		Oil		NGLs		Natural Gas		Total
		(MBbl)		(MBbl)		(MMcf)		(MBOE)
	Balance—January 1, 2011	224,196		30,082		303,544		304,869
	Extensions and discoveries	39,660		5,024		23,211		48,552
	Sales of minerals in place	(579	)	(632	)	(9,759	)	(2,837	)
	Purchases of minerals in place	114		58		1,639		445
	Production	(18,299	)	(2,074	)	(26,443	)	(24,780	)
	Revisions to previous estimates	15,052		5,151		(7,217	)	19,000
	Balance—December 31, 2011	260,144		37,609		284,975		345,249
	Extensions and discoveries	68,134		6,526		40,915		81,479
	Sales of minerals in place	(7,960	)	(320	)	(13,987	)	(10,611	)
	Production	(23,139	)	(2,766	)	(25,827	)	(30,209	)
	Revisions to previous estimates	4,106		(951	)	(61,812	)	(7,148	)
	Balance—December 31, 2012	301,285		40,098		224,264		378,760
	Extensions and discoveries	88,293		9,830		63,893		108,772
	Sales of minerals in place	(36,992	)	(4,777	)	(12,411	)	(43,838	)
	Purchases of minerals in place	14,543		1,311		7,751		17,146
	Production	(27,035	)	(2,821	)	(26,917	)	(34,342	)
	Revisions to previous estimates	7,327		1,228		20,934		12,044
	Balance—December 31, 2013	347,421		44,869		277,514		438,542
	Proved developed reserves:
	December 31, 2010	160,088		18,321		220,530		215,164
	December 31, 2011	180,975		22,109		211,297		238,300
	December 31, 2012	190,845		24,204		160,893		241,864
	December 31, 2013	198,204		23,721		183,129		252,446
	Proved undeveloped reserves:
	December 31, 2010	64,108		11,761		83,014		89,705
	December 31, 2011	79,169		15,500		73,678		106,949
	December 31, 2012	110,440		15,894		63,371		136,896
	December 31, 2013	149,217		21,148		94,385		186,096
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	'
	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):
		December 31,
		2013			2012			2011
	Future cash flows	$	35,178,399		$	29,308,752		$	26,815,086
	Future production costs	(12,973,292		)	(11,397,332		)	(8,908,131		)
	Future development costs	(5,355,383		)	(3,181,618		)	(1,982,813		)
	Future income tax expense	(3,954,401		)	(4,278,529		)	(4,875,973		)
	Future net cash flows	12,895,323			10,451,273			11,048,169
	10% annual discount for estimated timing of cash flows	(6,301,462		)	(5,044,240		)	(5,775,677		)
	Standardized measure of discounted future net cash flows	$	6,593,861		$	5,407,033		$	5,272,492
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	'
	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
		December 31,
		2013			2012			2011
	Beginning of year	$	5,407,033		$	5,272,492		$	3,667,606
	Sale of oil and gas produced, net of production costs	(2,010,925		)	(1,589,665		)	(1,415,469		)
	Sales of minerals in place	(1,064,195		)	(438,614		)	(67,600		)
	Net changes in prices and production costs	902,916			(1,061,495		)	2,246,014
	Extensions, discoveries and improved recoveries	2,827,321			3,708,780			1,156,740
	Previously estimated development costs incurred during the period	832,096			526,982			408,079
	Changes in estimated future development costs	(1,264,189		)	(1,498,592		)	(797,542		)
	Purchases of minerals in place	445,669			—			10,604
	Revisions of previous quantity estimates	313,069			(295,432		)	452,668
	Net change in income taxes	(335,637		)	255,328			(755,369		)
	Accretion of discount	540,703			527,249			366,761
	End of year	$	6,593,861		$	5,407,033		$	5,272,492
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves calculating average sales prices	'
		2013			2012			2011
	Oil (per Bbl)	$	90.8		$	87.15		$	89.18
	NGLs (per Bbl)	$	54.38		$	58.15		$	62.93
	Natural Gas (per Mcf)	$	4.3		$	3.21		$	4.39

QUARTERLY_FINANCIAL_DATA_UNAUD1

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2013
QUARTERLY FINANCIAL DATA (UNAUDITED)	'
Summary of the unaudited quarterly financial data	'
	The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2013 and 2012 (in thousands, except per share data):
		Three Months Ended
	Year ended December 31, 2013:	March 31,		June 30,		September 30,		December 31,
		2013		2013		2013		2013
	Oil, NGL and natural gas sales	$	605,114	$	651,868	$	706,543	$	703,024
	Operating profit (1)	$	252,806	$	269,528	$	316,764	$	280,311
	Net income (loss)	$	86,244	$	134,944	$	204,091	$	(59,276	)
	Basic earnings (loss) per share	$	0.73	$	1.14	$	1.72	$	(0.50	)
	Diluted earnings (loss) per share	$	0.72	$	1.14	$	1.71	$	(0.50	)
		Three Months Ended
	Year ended December 31, 2012:	March 31,		June 30,		September 30,		December 31,
		2012		2012		2012		2012
	Oil, NGL and natural gas sales	$	558,697	$	492,756	$	521,195	$	565,066
	Operating profit (1)	$	263,176	$	201,900	$	204,230	$	235,635
	Net income	$	98,446	$	150,851	$	83,113	$	81,689
	Basic earnings per share	$	0.84	$	1.28	$	0.7	$	0.69
	Diluted earnings per share	$	0.83	$	1.27	$	0.7	$	0.69
	(1)               Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.

SUMMARY_OF_SIGNIFICANT_ACCOUNT3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	12 Months Ended				1 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Mar. 31, 2012	Dec. 31, 2013
				Whiting USA Trust I	Whiting USA Trust II Units	Whiting USA Trust II Units
Accounts receivable trade	'	'	'	'	'	'
Oil and gas receivables collection period	'2 months	'	'	'	'	'
Allowance for doubtful account	$4.20	$3.90	'	'	'	'
Oil and Gas Properties	'	'	'	'	'	'
Interest cost capitalized	$1.50	$2.70	$3.60	'	'	'
Consolidation disclosures	'	'	'	'	'	'
Company retained ownership (as a percent)	'	'	'	15.80%	'	'
Trust units sold to the public (in shares)	'	18,400,000	'	11,677,500	18,400,000	18,400,000

SUMMARY_OF_SIGNIFICANT_ACCOUNT4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 2)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	item	MMcf
	MMcf
Revenue Recognition	'	'
Under (over) produced imbalance units (in MMcf)	-110.798	-53.536
Industry Segment and Geographic Information	'	'
Number of operating segments	1	'
Minimum	'	'
Property, Plant and Equipment	'	'
Estimated useful life	'4 years	'
Maximum	'	'
Property, Plant and Equipment	'	'
Estimated useful life	'33 years	'

SUMMARY_OF_SIGNIFICANT_ACCOUNT5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 3)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and gas sales | Credit concentration | Plains Marketing LP	'	'	'
Concentration of Credit Risk	'	'	'
Sales as percentage of oil and gas revenue	21.00%	20.00%	27.00%
Oil and gas sales | Credit concentration | Shell Trading US	'	'	'
Concentration of Credit Risk	'	'	'
Sales as percentage of oil and gas revenue	14.00%	14.00%	13.00%
Oil and gas sales | Credit concentration | Eighty Eight Oil Company	'	'	'
Concentration of Credit Risk	'	'	'
Sales as percentage of oil and gas revenue	11.00%	11.00%	8.00%
Oil and gas sales | Credit concentration | Bridger Trading LLC	'	'	'
Concentration of Credit Risk	'	'	'
Sales as percentage of oil and gas revenue	8.00%	11.00%	6.00%
Derivative contracts | Commodity price risk	'	'	'
Concentration of Credit Risk	'	'	'
Number of counterparties	8	'	'
Derivative contracts | Commodity price risk | JP Morgan Chase Bank	'	'	'
Concentration of Credit Risk	'	'	'
Outstanding derivative contracts as percentage of crude oil volumes hedged	29.00%	'	'
Derivative contracts | Commodity price risk | Canadian Imperial Bank of Commerce	'	'	'
Concentration of Credit Risk	'	'	'
Outstanding derivative contracts as percentage of crude oil volumes hedged	21.00%	'	'
Derivative contracts | Commodity price risk | The Bank of Nova Scotia	'	'	'
Concentration of Credit Risk	'	'	'
Outstanding derivative contracts as percentage of crude oil volumes hedged	12.00%	'	'
Derivative contracts | Commodity price risk | Bank of America Merrill Lynch	'	'	'
Concentration of Credit Risk	'	'	'
Outstanding derivative contracts as percentage of crude oil volumes hedged	12.00%	'	'

OIL_AND_GAS_PROPERTIES_Details

OIL AND GAS PROPERTIES (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
OIL AND GAS PROPERTIES	'	'
Proved leasehold costs	$1,633,495	$2,119,541
Unproved leasehold costs	372,298	362,483
Costs of completed wells and facilities	7,563,350	6,369,170
Wells and facilities in progress	496,007	360,804
Total oil and gas properties, successful efforts method	10,065,150	9,211,998
Accumulated depletion	-2,645,841	-2,564,081
Oil and gas properties, net	$7,419,309	$6,647,917

ACQUISITIONS_AND_DIVESTITURES_1

ACQUISITIONS AND DIVESTITURES (Details) (USD $)

12 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 20, 2013

Dec. 31, 2013

Oct. 31, 2013

Oct. 31, 2013

Oct. 31, 2013

Jul. 15, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 22, 2012

Jul. 28, 2011

18-May-12

Mar. 28, 2012

Mar. 18, 2011

Dec. 31, 2013

Feb. 15, 2011

Sep. 29, 2011

Williston Basin

Williston Basin

Big Tex prospect properties

Big Tex prospect properties

Big Tex prospect properties

Postle Properties

Postle Properties

Postle Properties

Postle Properties

Postle Properties

Postle Properties

Missouri Breaks field

Missouri Breaks field

Belfield gas processing plant

Whiting USA Trust II Units

Sustainable Water Resources, LLC

Sustainable Water Resources, LLC

North Dakota

Karnes, Live Oak, and DeWitt non-core properties

item

item

acre

Pecos County, TX

Reeves County, TX

Swaps

Swaps

Swaps

Swaps

Swaps

acre

acre

MBoe

acre

acre

acre

acre

Crude oil

Crude oil

Crude oil

Crude oil

Crude oil

item

bbl

Apr - Dec 2013

Jan - Dec 2014

Jan - Dec 2015

Jan - Mar 2016

bbl

bbl

bbl

bbl

Acquisitions and divestitures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gross acquisition area (in acres)

'

'

'

39,300

'

45,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net acquisition area (in acres)

'

'

'

17,300

'

32,200

30,800

1,400

'

'

'

'

'

'

13,300

23,400

'

'

'

'

6,000

'

Number of wells acquired

'

'

'

121

121

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

Purchase price for acquisition

'

'

'

$260,000,000

'

'

'

'

'

'

'

'

'

'

$33,300,000

$46,900,000

'

'

'

'

$40,000,000

'

Amount contributed in ownership

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000,000

'

'

'

Noncontrolling interest, ownership percentage by parent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75.00%

'

'

'

Noncontrolling interest, ownership percentage by noncontrolling owners

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

25.00%

'

'

Fair value of contributions by third party

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,300,000

'

'

'

Cash contributions by third party

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,500,000

'

'

'

Tangible and intangible assets contributed in fair value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,800,000

'

'

'

Allocation of purchase price:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proved properties

232,572,000

19,785,000

4,324,000

232,187,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unproved properties

174,103,000

119,175,000

191,482,000

27,335,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Oil in tank inventory

'

'

'

692,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accounts receivable

'

'

'

578,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset retirement obligations

'

'

'

-1,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total

2,902,733,000

2,242,226,000

1,841,779,000

258,892,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Divestitures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ownership interest sold (as a percent)

'

'

'

'

'

'

'

'

60.00%

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

Proceeds from sale

'

'

'

'

'

152,000,000

'

'

809,700,000

'

'

'

'

'

'

'

66,200,000

322,300,000

'

'

'

64,800,000

Pre tax gain on Divestiture

'

'

'

'

'

13,000,000

'

'

109,700,000

'

'

'

'

'

'

'

'

'

'

'

'

12,300,000

Number of units received in exchange of oil and gas properties contributed (in shares)

'

18,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,400,000

'

'

'

'

Price per unit of shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$20

'

'

'

'

Deferred gain on sale

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$128,200,000

'

'

'

'

Percentage of units issued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

Entitled to receive percentage of net proceeds from sale of oil and gas production

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

90.00%

'

'

'

'

Termination of net profits interest, cumulative production from underlying properties (in MBOE)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,790

'

'

'

'

Proved producing reserves conveyed (in MBOE)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,610

'

'

'

'

Aggregate notional amount of price risk derivatives (in Bbl)

'

'

'

'

'

'

'

'

'

5,910,400

1,677,500

2,007,500

1,825,000

400,400

'

'

'

'

'

'

'

'

Derivative, Price (in dollars per Bbl)

'

'

'

'

'

'

'

'

'

'

98.5

94.75

94.75

93.5

'

'

'

'

'

'

'

'

LONGTERM_DEBT_Details

LONG-TERM DEBT (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2010

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Sep. 26, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

7% Senior Subordinated Notes due 2014

7% Senior Subordinated Notes due 2014

6.5% Senior Subordinated Notes due 2018

6.5% Senior Subordinated Notes due 2018

6.5% Senior Subordinated Notes due 2018

5% Senior Notes due 2019

5% Senior Notes due 2019

5.75% Senior Notes due 2021

5.75% Senior Notes due 2021

5.75% Senior Notes due 2021

Whiting Oil and Gas Corporation

Whiting Oil and Gas Corporation

Whiting Oil and Gas Corporation

Whiting Oil and Gas Corporation

Whiting Oil and Gas Corporation

Whiting Oil and Gas Corporation

Whiting Oil and Gas Corporation

Whiting Oil and Gas Corporation

Whiting Oil and Gas Corporation

Credit agreement

Credit agreement

Credit agreement

Credit agreement

Credit agreement

Credit agreement

Credit agreement

Credit agreement

Credit agreement

Less than 0.25 to 1.0

Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0

Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0

Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0

Greater than or equal to 0.90 to 1.0

Federal Funds Rate

LIBOR

Debt disclosures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest Rate (as a percent)

'

'

7.00%

'

6.50%

'

6.50%

5.00%

5.00%

5.75%

5.75%

5.75%

'

'

'

'

'

'

'

'

'

Long-term debt

$2,653,834,000

$1,800,000,000

'

$250,000,000

$350,000,000

$350,000,000

'

$1,100,000,000

'

$1,203,834,000

'

'

'

$1,200,000,000

'

'

'

'

'

'

'

Unamortized debt premium

'

'

'

'

'

'

'

'

'

3,834,000

'

'

'

'

'

'

'

'

'

'

'

Five years of maturities for the Company's long-term debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2018

350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current borrowing capacity of credit facility

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000,000

'

'

'

'

'

'

'

'

Borrowing capacity of credit facility, net of letter of credit

'

'

'

'

'

'

'

'

'

'

'

'

1,197,000,000

'

'

'

'

'

'

'

'

Outstanding borrowing capacity of credit facility

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

Letters of credit borrowings outstanding

'

'

'

'

'

'

'

'

'

'

'

'

3,000,000

'

'

'

'

'

'

'

'

Maximum borrowing capacity of credit facility

'

'

'

'

'

'

'

'

'

'

'

'

2,800,000,000

'

'

'

'

'

'

'

'

Portion of line of credit available for issuance of letters of credit

'

'

'

'

'

'

'

'

'

'

'

'

50,000,000

'

'

'

'

'

'

'

'

Amount of revolving credit agreement available for additional letters of credit under the agreement

'

'

'

'

'

'

'

'

'

'

'

'

47,000,000

'

'

'

'

'

'

'

'

Variable interest rate basis

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'LIBOR

'LIBOR

'LIBOR

'LIBOR

'LIBOR

'federal funds

'LIBOR

Alternate variable interest rate basis

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'base loan rate

'base loan rate

'base loan rate

'base loan rate

'base loan rate

'

'

Basis points added to reference rate (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.50%

1.00%

Range, less than

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.25

0.5

0.75

0.9

1

'

'

Range, greater than or equal to

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

0.25

0.5

0.75

0.9

'

'

Applicable Margin for Base Rate Loans (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.50%

0.75%

1.00%

1.25%

1.50%

'

'

Applicable Margin for Eurodollar Loans (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.50%

1.75%

2.00%

2.25%

2.50%

'

'

Commitment Fee (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.38%

0.38%

0.50%

0.50%

0.50%

'

'

Restricted net assets

'

'

'

'

'

'

'

'

'

'

'

'

4,070,400,000

'

'

'

'

'

'

'

'

Retained earnings free from restrictions

'

'

'

'

'

'

'

'

'

'

'

'

$23,000,000

'

'

'

'

'

'

'

'

EBITDAX ratio (percentage)

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

Minimum consolidated current assets to consolidated current liabilities ratio (percentage)

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

LONGTERM_DEBT_Details_2

LONG-TERM DEBT (Details 2) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 20, 2013

Dec. 31, 2013

Dec. 31, 2013

Sep. 30, 2010

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Sep. 26, 2013

Oct. 31, 2013

Dec. 31, 2013

Williston Basin

Whiting Oil and Gas and Whiting Programs, Inc

6.5% Senior Subordinated Notes due 2018

6.5% Senior Subordinated Notes due 2018

5% Senior Notes due 2019

5% Senior Notes due 2019

5.75% Senior Notes due 2021

5.75% Senior Notes due 2021

5.75% Senior Notes due 2021

7% Senior Subordinated Notes due 2014

7% Senior Subordinated Notes due 2014

Debt disclosures

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate on debt instrument (as a percent)

'

'

'

6.50%

6.50%

5.00%

5.00%

5.75%

5.75%

5.75%

'

7.00%

Notes Issued

'

'

'

'

$350,000,000

'

$1,100,000,000

'

$800,000,000

$400,000,000

'

'

Payment for Redemption of Senior Debt

'

'

'

'

'

'

'

'

'

'

254,000,000

253,988,000

Percentage of Redemption Price

'

'

'

'

'

'

'

'

'

'

101.60%

'

Estimated fair value of Notes

'

'

'

371,000,000

'

1,122,000,000

'

1,260,000,000

'

'

'

'

Premium as a percentage of par

'

'

'

'

'

'

'

'

'

101.00%

'

'

Proceeds from issuance of debt

'

260,000,000

'

'

'

'

'

'

'

'

'

'

Senior subordinated notes redeemed, face amount

'

'

'

'

'

'

'

'

'

'

250,000,000

'

Loss on early extinguishment of debt

4,412,000

'

'

'

'

'

'

'

'

'

4,412,000

'

Cash charge related to the redemption premium

'

'

'

'

'

'

'

'

'

'

4,000,000

'

Non cash charges

'

'

'

'

'

'

'

'

'

'

$400,000

'

Percentage of ownership in subsidiary

'

'

100.00%

'

'

'

'

'

'

'

'

'

ASSET_RETIREMENT_OBLIGATIONS_D

ASSET RETIREMENT OBLIGATIONS (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations	'	'
Asset retirement obligations, current portion	$9,700,000	$11,600,000
Reconciliation of the Company's asset retirement obligations	'	'
Balance at the beginning of the period	97,818,000	69,721,000
Additional liability incurred	17,535,000	9,292,000
Revisions in estimated cash flows	12,225,000	23,162,000
Accretion expense	10,608,000	7,263,000
Obligations on sold properties	-3,630,000	-4,000
Liabilities settled	-8,408,000	-11,616,000
Balance at the end of the period	$126,148,000	$97,818,000

DERIVATIVE_FINANCIAL_INSTRUMEN2

DERIVATIVE FINANCIAL INSTRUMENTS (Details) (Whiting Petroleum Corporation, Crude oil)	Feb. 06, 2014
	bbl
Derivative Financial Instruments	'
Aggregate notional amount of price risk derivatives (in Bbl)	15,329,290
Collars | Jan - Dec 2014	'
Derivative Financial Instruments	'
Aggregate notional amount of price risk derivatives (in Bbl)	49,290
Derivative, Floor Price (in dollars per Bbl)	80
Derivative, Cap Price (in dollars per Bbl)	122.5
Three-way collars | Jan - Dec 2014	'
Derivative Financial Instruments	'
Aggregate notional amount of price risk derivatives (in Bbl)	15,280,000
Derivative, Floor Price (in dollars per Bbl)	85
Derivative, Strike Price (in dollars per Bbl)	70.94
Derivative, Cap Price (in dollars per Bbl)	103.35

DERIVATIVE_FINANCIAL_INSTRUMEN3

DERIVATIVE FINANCIAL INSTRUMENTS (Details 2)	12 Months Ended	1 Months Ended	12 Months Ended			12 Months Ended
	Dec. 31, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
		Whiting USA Trust II Units	Whiting USA Trust II Units	Whiting USA Trust II held by Whiting Petroleum	Whiting USA Trust II held by Whiting Petroleum	Third party public holders of Whiting USA Trust II	Third party public holders of Whiting USA Trust II
					Collars		Collars
					Crude oil		Crude oil
					Jan - Dec 2014		Jan - Dec 2014
					bbl		bbl
Derivative Financial Instruments	'	'	'	'	'	'	'
Trust units sold to the public (in shares)	18,400,000	18,400,000	18,400,000	'	'	'	'
Retention of net proceeds from underlying properties (as a percent)	'	'	'	10.00%	'	90.00%	'
Aggregate notional amount of price risk derivatives (in Bbl)	'	'	'	'	49,290	'	443,610
Derivative, Floor Price (in dollars per Bbl)	'	'	'	'	80	'	80
Derivative, Cap Price (in dollars per Bbl)	'	'	'	'	122.5	'	122.5

DERIVATIVE_FINANCIAL_INSTRUMEN4

DERIVATIVE FINANCIAL INSTRUMENTS (Details 3) (CO 2 Contract, USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
CO 2 Contract	'
Derivative Financial Instruments	'
The estimated fair value of the embedded derivative in this purchase contract asset	$36.40

DERIVATIVE_FINANCIAL_INSTRUMEN5

DERIVATIVE FINANCIAL INSTRUMENTS (Details 4) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Financial Instruments	'	'	'
(Gain) Loss Recognized in Income	$7,802	($85,911)	($24,857)
Not Designated as ASC 815 Hedges	'	'	'
Derivative Financial Instruments	'	'	'
(Gain) Loss Recognized in Income	7,802	-85,911	'
Commodity contracts | Gain (loss) on hedging activities | ASC 815 Cash Flow Hedging Relationships	'	'	'
Derivative Financial Instruments	'	'	'
Accumulated Other Comprehensive Income from Derivative Contracts	-1,958	2,338	'
Commodity contracts | Commodity derivative (gain) loss, net | Not Designated as ASC 815 Hedges	'	'	'
Derivative Financial Instruments	'	'	'
(Gain) Loss Recognized in Income	20,503	-75,782	'
Embedded commodity contracts | Commodity derivative (gain) loss, net | Not Designated as ASC 815 Hedges	'	'	'
Derivative Financial Instruments	'	'	'
(Gain) Loss Recognized in Income	($12,701)	($10,129)	'

DERIVATIVE_FINANCIAL_INSTRUMEN6

DERIVATIVE FINANCIAL INSTRUMENTS (Details 5) (Not Designated as ASC 815 Hedges, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Gross amounts of derivative assets and gross amounts offset	'	'
Gross Amounts of Recognized Assets	$60,168	$69,000
Gross Amounts Offset	-22,478	-33,949
Total financial assets	37,690	35,051
Commodity contracts | Prepaid Expenses and Other	'	'
Gross amounts of derivative assets and gross amounts offset	'	'
Gross Amounts of Recognized Assets	23,752	40,909
Gross Amounts Offset	-22,478	-31,437
Total financial assets	1,274	9,472
Commodity contracts | Other Long Term Assets	'	'
Gross amounts of derivative assets and gross amounts offset	'	'
Gross Amounts of Recognized Assets	'	4,053
Gross Amounts Offset	'	-2,189
Total financial assets	'	1,864
Embedded commodity contracts | Other Long Term Assets	'	'
Gross amounts of derivative assets and gross amounts offset	'	'
Gross Amounts of Recognized Assets	36,416	24,038
Gross Amounts Offset	'	-323
Total financial assets	$36,416	$23,715

DERIVATIVE_FINANCIAL_INSTRUMEN7

DERIVATIVE FINANCIAL INSTRUMENTS (Details 6) (Not Designated as ASC 815 Hedges, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Gross amounts of derivative liabilities and gross amounts offset	'	'
Gross Amounts of Recognized Liabilities	$25,960	$57,582
Gross Amounts Offset	-22,478	-33,949
Total financial liabilities	3,482	23,633
Commodity contracts | Current Derivative Liabilities	'	'
Gross amounts of derivative liabilities and gross amounts offset	'	'
Gross Amounts of Recognized Liabilities	25,960	53,392
Gross Amounts Offset	-22,478	-31,437
Total financial liabilities	3,482	21,955
Commodity contracts | Noncurrent Derivative Liabilities	'	'
Gross amounts of derivative liabilities and gross amounts offset	'	'
Gross Amounts of Recognized Liabilities	'	3,867
Gross Amounts Offset	'	-2,189
Total financial liabilities	'	1,678
Embedded commodity contracts | Noncurrent Derivative Liabilities	'	'
Gross amounts of derivative liabilities and gross amounts offset	'	'
Gross Amounts of Recognized Liabilities	'	323
Gross Amounts Offset	'	($323)

FAIR_VALUE_MEASUREMENTS_Detail

FAIR VALUE MEASUREMENTS (Details) (Recurring Basis, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Financial Assets	'	'
Total financial assets	$37,690	$35,051
Financial Liabilities	'	'
Total financial liabilities	3,482	23,633
Commodity contracts	'	'
Financial Assets	'	'
Financial assets - current	1,274	9,472
Financial assets - non-current	'	1,864
Financial Liabilities	'	'
Financial liabilities - current	3,482	21,955
Financial liabilities - non-current	'	1,678
Embedded commodity contracts	'	'
Financial Assets	'	'
Financial assets - non-current	36,416	23,715
Level 2	'	'
Financial Assets	'	'
Total financial assets	1,274	11,336
Financial Liabilities	'	'
Total financial liabilities	3,482	23,633
Level 2 | Commodity contracts	'	'
Financial Assets	'	'
Financial assets - current	1,274	9,472
Financial assets - non-current	'	1,864
Financial Liabilities	'	'
Financial liabilities - current	3,482	21,955
Financial liabilities - non-current	'	1,678
Level 3	'	'
Financial Assets	'	'
Total financial assets	36,416	23,715
Level 3 | Embedded commodity contracts	'	'
Financial Assets	'	'
Financial assets - non-current	$36,416	$23,715

FAIR_VALUE_MEASUREMENTS_Detail1

FAIR VALUE MEASUREMENTS (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy	'	'
Fair value asset, beginning of period	$23,715	$12,980
Unrealized gains (losses) on embedded commodity derivative contracts included in earnings	12,701	10,735
Fair value asset, end of period	$36,416	$23,715

FAIR_VALUE_MEASUREMENTS_Detail2

FAIR VALUE MEASUREMENTS (Details 3) (Embedded commodity contracts, Level 3)	12 Months Ended
	Dec. 31, 2013
Minimum	'
FAIR VALUE MEASURMENTS	'
Range of future price of NYMEX crude oil (in dollars per barrel)	79.87
Maximum	'
FAIR VALUE MEASURMENTS	'
Range of future price of NYMEX crude oil (in dollars per barrel)	95.75

FAIR_VALUE_MEASUREMENTS_Detail3

FAIR VALUE MEASUREMENTS (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Non-financial assets and liabilities measured at fair value on a nonrecurring basis	'	'	'
Loss (Before Tax) Year	$358,455,000	$107,855,000	$38,783,000
Nonrecurring | Proved oil and natural gas properties	'	'	'
Non-financial assets and liabilities measured at fair value on a nonrecurring basis	'	'	'
Net Carrying Value	106,114,000	23,473,000	'
Loss (Before Tax) Year	267,109,000	46,924,000	'
Net Carrying Value	373,200,000	70,400,000	'
Nonrecurring | Proved oil and natural gas properties | Rocky Mountains region and Michigan	'	'	'
Non-financial assets and liabilities measured at fair value on a nonrecurring basis	'	'	'
Loss (Before Tax) Year	220,800,000	'	'
Nonrecurring | Proved oil and natural gas properties | Rocky Mountains region	'	'	'
Non-financial assets and liabilities measured at fair value on a nonrecurring basis	'	'	'
Loss (Before Tax) Year	46,300,000	46,300,000	'
Nonrecurring | Proved oil and natural gas properties | Level 3	'	'	'
Non-financial assets and liabilities measured at fair value on a nonrecurring basis	'	'	'
Net Carrying Value	$106,114,000	$23,473,000	'

FAIR_VALUE_MEASUREMENTS_Detail4

FAIR VALUE MEASUREMENTS (Details 5) (Proved oil and natural gas properties, Level 3)	12 Months Ended
	Dec. 31, 2013
Proved oil and natural gas properties | Level 3	'
FAIR VALUE MEASURMENTS	'
Risk-adjusted discount rate (as a percent)	15.00%

DEFERRED_COMPENSATION_Details

DEFERRED COMPENSATION (Details) (Production Participation Plan, USD $)

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 1995

Dec. 31, 1994

Dec. 31, 2013

Dec. 31, 1995

Dec. 31, 1994

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

item

Minimum

Minimum

Minimum

Maximum

Maximum

Maximum

General and administrative expense

General and administrative expense

General and administrative expense

Exploration expense

Exploration expense

Exploration expense

Deferred Compensation

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of overriding royalty interest allocated

'

'

'

2.00%

'

'

3.00%

'

'

'

'

'

'

Percentage of oil and gas sales less lease operating expenses and production taxes allocated

'

1.75%

1.75%

'

5.00%

5.00%

'

'

'

'

'

'

'

Accrued compensation expense allocation

'

'

'

'

'

'

'

$66.50

$44.70

$34.10

$6.80

$4.60

$4.20

Additional Deferred Compensation

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of plan interests paid to employees at year end

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of employees vesting ratably per year

20.00%

'

'

'

'

'

'

'

'

'

'

'

'

Plan Period

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

Fully vested age of employees

62

'

'

'

'

'

'

'

'

'

'

'

'

Number of years average historical NYMEX prices used in calculation of liability

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

Three-year average historical prices of crude oil

95.6

'

'

'

'

'

'

'

'

'

'

'

'

Three-year average historical prices of natural gas

3.49

'

'

'

'

'

'

'

'

'

'

'

'

Distribution period after date of termination

'12 months

'

'

'

'

'

'

'

'

'

'

'

'

Distribution period after change in control

'1 month

'

'

'

'

'

'

'

'

'

'

'

'

Fully Vested Lump sum Cash Payment to Employees in Case of Termination of Plan or Change of Control

186.7

'

'

'

'

'

'

'

'

'

'

'

'

Amount attributable to proved undeveloped oil and gas properties

$19.20

'

'

'

'

'

'

'

'

'

'

'

'

DEFERRED_COMPENSATION_Details_

DEFERRED COMPENSATION (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Deferred Compensation	'	'
Long-term Production Participation Plan liability at beginning of the period	$94,483,000	$80,659,000
Change in liability for accretion, vesting, changes in estimates and new Plan year activity	66,284,000	63,135,000
Accrued compensation expense reflected as a current liability	-73,264,000	-49,311,000
Long-term Production Participation Plan liability at end of the period	87,503,000	94,483,000
Postle Properties	'	'
Deferred Compensation	'	'
Accrued compensation expense reflected as a current liability	23,900,000	'
Offsetting benefit to Production Participation Plan	$19,400,000	'

DEFERRED_COMPENSATION_Details_1

DEFERRED COMPENSATION (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
DEFERRED COMPENSATION	'	'	'
Employer's contribution in employees retirement plan	$7.90	$5.90	$5
Employees vest in employer contribution Percentage, per year of completed service	20.00%	'	'

SHAREHOLDERS_EQUITY_AND_NONCON2

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Details) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

In Thousands, except Share data, unless otherwise specified

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Mar. 31, 2013

Feb. 22, 2011

Dec. 31, 2013

Dec. 31, 2011

31-May-11

Jun. 30, 2009

Dec. 31, 2012

Dec. 31, 2013

Mar. 31, 2013

Feb. 22, 2011

Common Stock

Common Stock

Common Stock

Common Stock

Common Stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

Authorized shares

'

300,000,000

300,000,000

'

'

300,000,000

'

175,000,000

'

'

'

'

'

Stock split approved

2

'

'

'

2

'

'

'

'

'

'

'

'

Shares received in stock split for each share held

'

'

'

'

1

'

'

'

'

'

'

'

'

Adjustment to paid-in capital for two-for-one-stock split

'

'

'

'

$100

'

$59

'

'

'

'

'

'

Adjustments to additional paid in capital stock split per share (in dollars per share)

'

$0.00

$0.00

'

$0.00

'

'

'

'

'

'

'

'

Interest rate on convertible perpetual preferred stock (as a percent)

'

'

'

'

'

'

'

'

6.25%

6.25%

'

'

'

6.25% convertible perpetual preferred stock, shares issued

'

'

'

'

'

'

'

'

3,450,000

172,391

0

'

'

Conversion price (in dollars per share)

'

'

'

'

'

'

'

'

$43.42

'

'

'

$21.71

6.25% convertible perpetual preferred stock, shares issue Price per share (in dollars per share)

'

'

'

'

'

'

'

'

$100

'

'

'

'

6.25% convertible perpetual preferred stock, shares outstanding

'

'

'

'

'

'

'

'

'

172,391

0

172,129

'

Dividend on preferred stock per share Per annum (in dollars per share)

'

'

'

'

'

'

'

'

$6.25

'

'

'

'

Common stock issued on conversion of preferred stock (in shares)

'

'

'

792,919

'

794,000

1,000

'

'

'

'

'

'

SHAREHOLDERS_EQUITY_AND_NONCON3

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Details 2)	12 Months Ended
	Dec. 31, 2013
Stock options	'
Share-based compensation disclosures	'
Maximum number of Shares per employee	600,000
Stock Appreciation Rights (SARs)	'
Share-based compensation disclosures	'
Maximum number of Shares per employee	600,000
Restricted Stock Units (RSUs)	'
Share-based compensation disclosures	'
Maximum number of Shares per employee	300,000
2013 Equity Plan	'
Share-based compensation disclosures	'
Number of shares authorized upon shareholder's approval	5,300,000
Number of options available for grant	5,380,594

SHAREHOLDERS_EQUITY_AND_NONCON4

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Details 3) (USD $)	1 Months Ended			12 Months Ended
In Millions, except Share data, unless otherwise specified	Jan. 31, 2013	Jan. 31, 2012	Jan. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
				item	item	item
Share-based compensation disclosures	'	'	'	'	'	'
Stock compensation expense	'	'	'	22.4	18.2	13.5
Restricted stock	'	'	'	'	'	'
Summary of nonvested restricted stock	'	'	'	'	'	'
Balance at the beginning of the period (in shares)	951,026	724,395	869,370	951,026	724,395	869,370
Granted (in shares)	'	'	'	940,792	592,400	304,355
Vested (in shares)	'	'	'	-347,824	-357,170	-429,136
Forfeited (in shares)	'	'	'	-99,684	-8,599	-20,194
Balance at the end of the period (in shares)	'	'	'	1,444,310	951,026	724,395
Weighted Average Grant Date Fair Value	'	'	'	'	'	'
Balance at the beginning of the period (in dollars per share)	$37.02	$29.88	$16.27	37.02	29.88	16.27
Granted (in dollars per share)	'	'	'	27.59	34.45	48.48
Vested (in dollars per share)	'	'	'	35.32	17.91	15.32
Forfeited (in dollars per share)	'	'	'	30.95	51.72	33.53
Balance at the end of the period (in dollars per share)	'	'	'	31.71	37.02	29.88
Unrecognized compensation cost	'	'	'	11.8	'	'
Weighted average period over which cost will be recognized	'	'	'	'1 year 8 months 12 days	'	'
Total fair value of restricted stock vested	'	'	'	16.8	18.9	26
Restricted stock | Executive officers and employees	'	'	'	'	'	'
Share-based compensation disclosures	'	'	'	'	'	'
Vesting (service) period	'	'	'	'3 years	'	'
Restricted stock | Directors | Minimum	'	'	'	'	'	'
Share-based compensation disclosures	'	'	'	'	'	'
Vesting (service) period	'	'	'	'1 year	'	'
Restricted stock | Directors | Maximum	'	'	'	'	'	'
Share-based compensation disclosures	'	'	'	'	'	'
Vesting (service) period	'	'	'	'3 years	'	'
Restricted stock | Market-based vesting criteria | Executive officers	'	'	'	'	'	'
Share-based compensation disclosures	'	'	'	'	'	'
Vesting (service) period	'	'	'	'3 years	'	'
Assumptions used in valuing awards	'	'	'	'	'	'
Number of simulations	'	'	'	65,000	65,000	65,000
Expected volatility (as a percent)	'	'	'	43.10%	51.90%	75.80%
Risk-free interest rate (as a percent)	'	'	'	0.41%	0.35%	1.00%
Dividend yield (as a percent)	'	'	'	0.00%	0.00%	0.00%
Summary of nonvested restricted stock	'	'	'	'	'	'
Granted (in shares)	751,872	444,501	201,420	'	'	'
Weighted Average Grant Date Fair Value	'	'	'	'	'	'
Granted (in dollars per share)	$23.01	$29.45	$42.20	'	'	'

SHAREHOLDERS_EQUITY_AND_NONCON5

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Details 4) (Stock options, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock options	'	'	'
Share-based compensation disclosures	'	'	'
Vesting (service) period	'3 years	'	'
Assumptions used in valuing awards	'	'	'
Risk-free interest rate (as a percent)	'	1.19%	2.47%
Expected volatility (as a percent)	'	61.40%	59.30%
Expected term	'	'6 years	'6 years
Grant date fair value (in dollars per share)	'	$28.88	$34.15
Dividend yield (as a percent)	'	0.00%	0.00%
Summary of stock options outstanding	'	'	'
Balance at the beginning of the period (in shares)	422,695	377,336	296,516
Granted (in shares)	'	45,359	80,820
Forfeited or expired (in shares)	-1,855	'	'
Balance at the end of the period (in shares)	420,840	422,695	377,336
Options vested and expected to vest (in shares)	420,840	'	'
Options exercisable (in shares)	365,511	'	'
Weighted Average Exercise Price per Share	'	'	'
Balance at the beginning of the period (in dollars per share)	$28.79	$26.09	$16.78
Granted (in dollars per share)	'	$51.22	$60.28
Forfeited or expired (in dollars per share)	$60.28	'	'
Balance at the end of the period (in dollars per share)	$28.65	$28.79	$26.09
Options vested and expected to vest (in dollars per share)	$28.65	'	'
Options exercisable (in dollars per share)	$24.61	'	'
Aggregate Intrinsic Value, options outstanding, end of period	$13,979,600	'	'
Options vested and expected to vest, Aggregate Intrinsic Value	13,979,600	'	'
Options exercisable, Aggregate Intrinsic Value	13,617,800	'	'
Weighted Average Remaining Contractual Term, options outstanding	'5 years 10 months 24 days	'	'
Weighted Average Remaining Contractual Term, options vested and expected to vest	'5 years 10 months 24 days	'	'
Weighted Average Remaining Contractual Term, options exercisable	'5 years 8 months 12 days	'	'
Unrecognized compensation	'	'	'
Unrecognized compensation cost	$200,000	'	'
Weighted average period over which cost will be recognized	'1 year	'	'

SHAREHOLDERS_EQUITY_AND_NONCON6

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Details 5) (USD $)	12 Months Ended		0 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Feb. 22, 2011	Dec. 31, 2013	Dec. 31, 2006	Dec. 31, 2013	Dec. 31, 2013
		Series A Junior Participating Preferred Stock	Common Stock	Common Stock	Common Stock	Rights	Rights
							Series A Junior Participating Preferred Stock
Rights Agreement disclosures	'	'	'	'	'	'	'
Number of Preferred Share Purchase Rights declared as a dividend on common stock	'	'	'	'	1	'	'
Stock split approved	2	'	2	'	'	'	'
Number of rights outstanding per common share	'	'	'	$0.50	'	'	'
Number of securities into which each warrant or right may be converted	'	'	'	'	'	'	0.01
Junior Participating Preferred Stock par value	'	$0.00	'	'	'	'	'
Price of one hundredth of a share, Series A Junior Participating Preferred Stock	'	'	'	'	'	$180	'
Minimum percentage ownership for preferred rights price to apply	'	'	'	15.00%	'	'	'
Redemption price per share, Series A Junior Participating Preferred Stock	'	'	'	'	'	$0.00	'

SHAREHOLDERS_EQUITY_AND_NONCON7

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Details 6) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Mar. 18, 2011
				Sustainable Water Resources, LLC	Sustainable Water Resources, LLC
Noncontrolling Interest disclosures	'	'	'	'	'
Third party ownership interest (as a percent)	'	'	'	25.00%	25.00%
Balance at the beginning of the period	$8,184	$8,274	'	'	'
Net income (loss)	-52	-90	-59	'	'
Balance at the end of the period	$8,132	$8,184	$8,274	'	'

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current income tax expense (refund):	'	'	'
Federal	$7,060	'	$107
State	-6,074	-669	3,746
Total current income tax expense	986	-669	3,853
Deferred income tax expense:	'	'	'
Federal	196,787	233,468	272,653
State	8,095	15,113	12,185
Total deferred income tax expense	204,882	248,581	284,838
Total income tax expense	$205,868	$247,912	$288,691

INCOME_TAXES_Details_2

INCOME TAXES (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
INCOME TAXES	'	'	'
U.S. statutory income tax rate (as a percent)	35.00%	35.00%	35.00%
Income before income taxes	'	'	'
U.S. statutory income tax expense	$200,155	$231,704	$273,112
State income taxes, net of federal benefit	13,962	14,444	16,602
State income tax credits	-10,525	'	'
Statutory depletion	-796	-620	-697
Enacted changes in state tax laws	-1,416	'	-1,842
Permanent items	2,122	1,524	1,420
Other	2,366	860	96
Total income tax expense	$205,868	$247,912	$288,691

INCOME_TAXES_Details_3

INCOME TAXES (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred income tax assets:	'	'
Net operating loss carryforward	$438,922	$520,980
Derivative instruments	'	19,957
Production Participation Plan liability	32,245	34,865
Tax sharing liability	9,439	8,312
Asset retirement obligations	23,642	19,759
Underwriter fees	10,974	12,677
Restricted stock compensation	13,384	9,852
Enhanced oil recovery credit carryforwards	7,946	7,946
Alternative minimum tax credit carryforwards	18,452	11,391
Foreign tax credit carryforwards	1,230	1,230
Other	2,004	1,508
Total deferred income tax assets	558,238	648,477
Less valuation allowances	-1,230	-1,230
Net deferred income tax assets	557,008	647,247
Deferred income tax liabilities:	'	'
Oil and gas properties	1,675,916	1,555,142
Trust distributions	149,332	165,180
Derivative instruments	10,438	'
Total deferred income tax liabilities	1,835,686	1,720,322
Total net deferred income tax liabilities	$1,278,678	$1,073,075

INCOME_TAXES_Details_4

INCOME TAXES (Details 4) (Federal, USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Federal	'
Operating Loss Carryforwards	'
Federal operating loss carryforwards	$1,255.20
Net operating loss carryforwards related to tax deductions that deviate from compensation expense	$50.50

INCOME_TAXES_Details_5

INCOME TAXES (Details 5) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Liabilities:	'	'
Current deferred income taxes	$648	$9,394
Non-current deferred income taxes	1,278,030	1,063,681
Total net deferred income tax liabilities	$1,278,678	$1,073,075

INCOME_TAXES_Details_6

INCOME TAXES (Details 6) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2010
Liability for unrecognized tax benefits	'	'	'
Balance at the beginning of the period	$299,000	$170,000	$299,000
Decrease related to tax position taken in a prior period	-129,000	'	'
Balance at the end of the period	170,000	170,000	299,000
Unrecognized tax benefits that would affect the annual effective income tax rate	'	$200,000	'

EARNINGS_PER_SHARE_Details

EARNINGS PER SHARE (Details) (USD $)	3 Months Ended								12 Months Ended
Share data in Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Numerator:	'	'	'	'	'	'	'	'	'	'	'
Net income available to shareholders	'	'	'	'	'	'	'	'	$366,055,000	$414,189,000	$491,687,000
Preferred stock dividends	'	'	'	'	'	'	'	'	-494,000	-1,077,000	-1,077,000
Net income available to common shareholders, basic	'	'	'	'	'	'	'	'	365,561,000	413,112,000	490,610,000
Denominator:	'	'	'	'	'	'	'	'	'	'	'
Weighted average shares outstanding, basic	'	'	'	'	'	'	'	'	118,260	117,601	117,345
Numerator:	'	'	'	'	'	'	'	'	'	'	'
Net income available to common shareholders, basic	'	'	'	'	'	'	'	'	365,561,000	413,112,000	490,610,000
Preferred stock dividends	'	'	'	'	'	'	'	'	538,000	1,077,000	1,077,000
Adjusted net income available to common shareholders, diluted	'	'	'	'	'	'	'	'	366,099,000	414,189,000	491,687,000
Denominator:	'	'	'	'	'	'	'	'	'	'	'
Weighted average shares outstanding, basic	'	'	'	'	'	'	'	'	118,260	117,601	117,345
Restricted stock and stock options (in shares)	'	'	'	'	'	'	'	'	957	633	529
Convertible perpetual preferred stock (in shares)	'	'	'	'	'	'	'	'	371	794	794
Weighted average shares outstanding, diluted	'	'	'	'	'	'	'	'	119,588	119,028	118,668
Earnings (loss) per common share, basic (in dollars per share)	($0.50)	$1.72	$1.14	$0.73	$0.69	$0.70	$1.28	$0.84	$3.09	$3.51	$4.18
Earnings (loss) per common share, diluted (in dollars per share)	($0.50)	$1.71	$1.14	$0.72	$0.69	$0.70	$1.27	$0.83	$3.06	$3.48	$4.14
Decrease in accumulated preferred stock dividends	'	'	'	'	'	'	'	'	$40,000	$0	$0

EARNINGS_PER_SHARE_Details_2

EARNINGS PER SHARE (Details 2)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Restricted stock	'	'	'
Shares excluded from Earnings Per Share calculation	'	'	'
Stock options excluded from earnings per share calculation (in shares)	173,778	141,807	113,228
Stock options	'	'	'
Shares excluded from Earnings Per Share calculation	'	'	'
Restricted stock excluded from earnings per share calculation (in shares)	8,689	7,720	2,285

RELATED_PARTY_TRANSACTIONS_Det

RELATED PARTY TRANSACTIONS (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012
		Whiting USA Trust I	Whiting USA Trust I
Related party transactions	'	'	'
Percentage of ownership in subsidiary	'	15.80%	'
Whiting's ownership interest (in units)	'	2,186,389	'
Assets	'	'	'
Unit distributions due from Trust I	'	$1,093,000	$929,000
Liabilities	'	'	'
Unit distributions payable to Trust I	'	6,932,000	5,731,000
Payments of unit distributions, net of state tax withholdings	'	30,700,000	'
Distributions back from the trust	$5,833,000	$4,700,000	'

RELATED_PARTY_TRANSACTIONS_Det1

RELATED PARTY TRANSACTIONS (Details 2) (Alliant Energy, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	item
Alliant Energy	'	'	'
Tax Sharing arrangements	'	'	'
Percentage of tax benefits due to affiliate related to step-up of tax basis assets	90.00%	'	'
Payments under agreement	$1.80	$2.30	$1.90
Interest expense	3.1	2.2	2.1
Current liability due to Alliant Energy under tax sharing agreement	$23.90	'	'
Working interest in offshore platforms (as a percent)	6.00%	'	'
Number of offshore platforms in California that the Company has working interest in	3	'	'

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Non-cancelable leases	'	'	'
2014	$6,279,000	'	'
2015	5,872,000	'	'
2016	5,387,000	'	'
2017	5,250,000	'	'
2018	4,629,000	'	'
Thereafter	1,374,000	'	'
Total	28,791,000	'	'
Rental expense	5,000,000	5,700,000	4,400,000
Non-cancelable operating leases and unconditional purchase obligations	'	'	'
2014	124,955,000	'	'
2015	54,403,000	'	'
2016	10,042,000	'	'
2017	12,150,000	'	'
2018	8,729,000	'	'
Thereafter	1,374,000	'	'
Total	211,653,000	'	'
Denver, Colorado office	'	'	'
Non-cancelable leases	'	'	'
Administrative office space (in square feet)	172,400	'	'
Midland, Texas office	'	'	'
Non-cancelable leases	'	'	'
Administrative office space (in square feet)	47,900	'	'
Dickinson, North Dakota office	'	'	'
Non-cancelable leases	'	'	'
Administrative office space (in square feet)	20,000	'	'
Drilling rig	'	'	'
Unconditional purchase obligations	'	'	'
2014	87,610,000	'	'
2015	48,531,000	'	'
2016	1,755,000	'	'
Total	137,896,000	'	'
Construction and drilling contract	'	'	'
Unconditional purchase obligations	'	'	'
2014	31,066,000	'	'
2016	2,900,000	'	'
2017	6,900,000	'	'
2018	4,100,000	'	'
Total	$44,966,000	'	'

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	item
Drilling Rig	'	'	'
Commitments disclosures	'	'	'
Number of contracts with drilling rig companies	12	'	'
Termination penalties	$101.10	'	'
Number of drilling rigs having price adjustment clauses	2	'	'
Amount spent under contractual commitment	92.8	101.1	49.8
Drilling Rig | Expire in 2014	'	'	'
Commitments disclosures	'	'	'
Number of contracts with drilling rig companies	6	'	'
Drilling Rig | Expire in 2015	'	'	'
Commitments disclosures	'	'	'
Number of contracts with drilling rig companies	4	'	'
Drilling Rig | Expire in 2016	'	'	'
Commitments disclosures	'	'	'
Number of contracts with drilling rig companies	2	'	'
Construction and Drilling Contract	'	'	'
Commitments disclosures	'	'	'
Capital expenditure obligation under contract	51.4	'	'
Number of CO2 wells to be drilled in Bravo Dome field	46	'	'
Amount spent under contractual commitment	$6.40	'	'

COMMITMENTS_AND_CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	item
Ship-Or-Pay Arrangements | December 2017 expiration	'	'	'
Commitments disclosures	'	'	'
Number of Ship-or-pay agreements	1	'	'
CO2 Take-Or-Pay Agreements	'	'	'
Commitments disclosures	'	'	'
Number of take or pay purchase agreements	3	'	'
Number of suppliers with take or pay purchase agreements	2	'	'
Payments under purchase contracts	$88,100,000	$86,000,000	$69,800,000
Future commitments under purchase agreements	$632,600,000	'	'
CO2 Take-Or-Pay Agreements | December 2014 expiration	'	'	'
Commitments disclosures	'	'	'
Number of take or pay purchase agreements	1	'	'
CO2 Take-Or-Pay Agreements | December 2017 expiration	'	'	'
Commitments disclosures	'	'	'
Number of take or pay purchase agreements	1	'	'
CO2 Take-Or-Pay Agreements | December 2029 expiration	'	'	'
Commitments disclosures	'	'	'
Number of take or pay purchase agreements	1	'	'

COMMITMENTS_AND_CONTINGENCIES_4

COMMITMENTS AND CONTINGENCIES (Details 4)	Dec. 31, 2013
	MMcf
Natural gas	'
Delivery commitments	'
Delivery commitments for year 2014	4,000
Crude oil	'
Delivery commitments	'
Delivery commitments for year 2015	9,100
Delivery commitments for year 2016	11,000
Delivery commitments for year 2017	12,800
Delivery commitments for year 2018	14,600
Delivery commitments for year 2019	16,400

OIL_AND_GAS_ACTIVITIES_Details

OIL AND GAS ACTIVITIES (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cost Incurred in oil and gas producing activities	'	'	'
Development	$2,132,824,000	$1,667,182,000	$1,245,150,000
Proved property acquisition	232,572,000	19,785,000	4,324,000
Unproved property acquisition	174,103,000	119,175,000	191,482,000
Exploration	363,234,000	436,084,000	400,823,000
Total	2,902,733,000	2,242,226,000	1,841,779,000
Addition to Oil and Gas Properties for Asset Retirement Costs related to new wells drilled or acquired	$29,800,000	$36,300,000	$4,900,000

OIL_AND_GAS_ACTIVITIES_Details1

OIL AND GAS ACTIVITIES (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	item
Net changes in capitalized exploratory well costs	'	'	'
Balance at the beginning of the period	$108,861,000	$90,519,000	$4,434,000
Additions to capitalized exploratory well costs pending the determination of proved reserves	281,951,000	384,223,000	354,962,000
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	-291,962,000	-358,625,000	-267,847,000
Capitalized exploratory well costs charged to expense	-13,472,000	-7,256,000	-1,030,000
Balance at the end of the period	85,378,000	108,861,000	90,519,000
Geographic information	'	'	'
Capitalized exploratory cost that are unevaluated	10,300,000	'	'
Number of exploratory wells that have been under evaluation for more than one year	1	'	'
Costs capitalized in 2013	'	'	'
Geographic information	'	'	'
Capitalized exploratory cost that are unevaluated	7,700,000	'	'
Costs capitalized in 2012	'	'	'
Geographic information	'	'	'
Capitalized exploratory cost that are unevaluated	$2,600,000	'	'

DISCLOSURES_ABOUT_OIL_AND_GAS_2

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	MBoe	MBoe	MBoe	MBoe
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	'	'	'	'
Percentage of proved reserve quantities and related future cash flows reviewed by independent petroleum engineers	100.00%	'	'	'
Summary of changes in quantities of proved oil and gas reserves	'	'	'	'
Beginning balance of proved oil and gas reserve	378,760	345,249	304,869	'
Extensions and discoveries	108,772	81,479	48,552	'
Sales of minerals in place	-43,838	-10,611	-2,837	'
Purchases of minerals in place	17,146	'	445	'
Production	-34,342	-30,209	-24,780	'
Revisions to previous estimates	12,044	-7,148	19,000	'
Ending balance of proved oil and gas reserves	438,542	378,760	345,249	'
Proved developed reserves:	'	'	'	'
Proved developed reserves	252,446	241,864	238,300	215,164
Proved undeveloped reserves:	'	'	'	'
Proved undeveloped reserves	186,096	136,896	106,949	89,705
Oil	'	'	'	'
Summary of changes in quantities of proved oil and gas reserves	'	'	'	'
Beginning balance of proved oil and gas reserve	301,285	260,144	224,196	'
Extensions and discoveries	88,293	68,134	39,660	'
Sales of minerals in place	-36,992	-7,960	-579	'
Purchases of minerals in place	14,543	'	114	'
Production	-27,035	-23,139	-18,299	'
Revisions to previous estimates	7,327	4,106	15,052	'
Ending balance of proved oil and gas reserves	347,421	301,285	260,144	'
Proved developed reserves:	'	'	'	'
Proved developed reserves	198,204	190,845	180,975	160,088
Proved undeveloped reserves:	'	'	'	'
Proved undeveloped reserves	149,217	110,440	79,169	64,108
NGLs	'	'	'	'
Summary of changes in quantities of proved oil and gas reserves	'	'	'	'
Beginning balance of proved oil and gas reserve	40,098	37,609	30,082	'
Extensions and discoveries	9,830	6,526	5,024	'
Sales of minerals in place	-4,777	-320	-632	'
Purchases of minerals in place	1,311	'	58	'
Production	-2,821	-2,766	-2,074	'
Revisions to previous estimates	1,228	-951	5,151	'
Ending balance of proved oil and gas reserves	44,869	40,098	37,609	'
Proved developed reserves:	'	'	'	'
Proved developed reserves	23,721	24,204	22,109	18,321
Proved undeveloped reserves:	'	'	'	'
Proved undeveloped reserves	21,148	15,894	15,500	11,761
Natural gas	'	'	'	'
Summary of changes in quantities of proved oil and gas reserves	'	'	'	'
Beginning balance of proved oil and gas reserve	224,264	284,975	303,544	'
Extensions and discoveries	63,893	40,915	23,211	'
Sales of minerals in place	-12,411	-13,987	-9,759	'
Purchases of minerals in place	7,751	'	1,639	'
Production	-26,917	-25,827	-26,443	'
Revisions to previous estimates	20,934	-61,812	-7,217	'
Ending balance of proved oil and gas reserves	277,514	224,264	284,975	'
Proved developed reserves:	'	'	'	'
Proved developed reserves	183,129	160,893	211,297	220,530
Proved undeveloped reserves:	'	'	'	'
Proved undeveloped reserves	94,385	63,371	73,678	83,014

DISCLOSURES_ABOUT_OIL_AND_GAS_3

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 2)	12 Months Ended					12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Sep. 20, 2013	Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2011
	MBoe	MBoe	MBoe	Williston Basin	Williston Basin	Oil	NGLs	Natural gas
				item	item	MBoe	MBoe	item
								MBoe
Reserve Quantities	'	'	'	'	'	'	'	'
Number of wells acquired	'	'	'	121	121	'	'	'
Revisions to estimated caused by higher crude oil prices incorporated into the Company's reserve estimates	4,900	-11,800	4,700	'	'	'	'	'
Revisions to estimated attributable to reservoir analysis and well performance	7,100	4,700	14,300	'	'	10,900	4,800	-1,400
Number of wells production completed	'	'	'	'	'	'	'	2

DISCLOSURES_ABOUT_OIL_AND_GAS_4

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 3) (Production Participation Plan)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 1995	Dec. 31, 1994
Minimum	'	'	'
Deferred Compensation	'	'	'
Percentage of overriding royalty interest allocated	'	'	2.00%
Percentage of oil and gas sales less lease operating expenses and production taxes allocated	1.75%	1.75%	'
Maximum	'	'	'
Deferred Compensation	'	'	'
Percentage of overriding royalty interest allocated	'	'	3.00%
Percentage of oil and gas sales less lease operating expenses and production taxes allocated	5.00%	5.00%	'

DISCLOSURES_ABOUT_OIL_AND_GAS_5

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	'	'	'
Discounted rate for future net cash flow (as a percent)	10.00%	'	'
Future cash flows	$35,178,399,000	$29,308,752,000	$26,815,086,000
Future production costs	-12,973,292,000	-11,397,332,000	-8,908,131,000
Future development costs	-5,355,383,000	-3,181,618,000	-1,982,813,000
Future income tax expense	-3,954,401,000	-4,278,529,000	-4,875,973,000
Future net cash flows	12,895,323,000	10,451,273,000	11,048,169,000
10% annual discount for estimated timing of cash flows	-6,301,462,000	-5,044,240,000	-5,775,677,000
Standardized measure of discounted future net cash flows	6,593,861,000	5,407,033,000	5,272,492,000
Increase (Decrease) in undiscounted future cash flow if hedging impact considered	'	($20,200,000)	($50,700,000)

DISCLOSURES_ABOUT_OIL_AND_GAS_6

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 5) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas	'	'	'
Beginning of year	$5,407,033	$5,272,492	$3,667,606
Sale of oil and gas produced, net of production costs	-2,010,925	-1,589,665	-1,415,469
Sales of minerals in place	-1,064,195	-438,614	-67,600
Net changes in prices and production costs	902,916	-1,061,495	2,246,014
Extensions, discoveries and improved recoveries	2,827,321	3,708,780	1,156,740
Previously estimated development costs incurred during the period	832,096	526,982	408,079
Changes in estimated future development costs	-1,264,189	-1,498,592	-797,542
Purchases of minerals in place	445,669	'	10,604
Revisions of previous quantity estimates	313,069	-295,432	452,668
Net change in income taxes	-335,637	255,328	-755,369
Accretion of discount	540,703	527,249	366,761
End of year	$6,593,861	$5,407,033	$5,272,492

DISCLOSURES_ABOUT_OIL_AND_GAS_7

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details 6)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil (per Bbl)	'	'	'
Weighted Average Sales Price	'	'	'
Weighted average sales prices	90.8	87.15	89.18
NGLs (per Bbl)	'	'	'
Weighted Average Sales Price	'	'	'
Weighted average sales prices	54.38	58.15	62.93
Natural Gas (per Mcf)	'	'	'
Weighted Average Sales Price	'	'	'
Weighted average sales prices	4.3	3.21	4.39

QUARTERLY_FINANCIAL_DATA_UNAUD2

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
QUARTERLY FINANCIAL DATA (UNAUDITED)	'	'	'	'	'	'	'	'	'	'	'
Oil, NGL and natural gas sales	$703,024	$706,543	$651,868	$605,114	$565,066	$521,195	$492,756	$558,697	$2,666,549	$2,137,714	$1,860,146
Operating profit	280,311	316,764	269,528	252,806	235,635	204,230	201,900	263,176	'	'	'
Net income (loss)	($59,276)	$204,091	$134,944	$86,244	$81,689	$83,113	$150,851	$98,446	$366,003	$414,099	$491,628
Earnings (loss) per common share, basic (in dollars per share)	($0.50)	$1.72	$1.14	$0.73	$0.69	$0.70	$1.28	$0.84	$3.09	$3.51	$4.18
Earnings (loss) per common share, diluted (in dollars per share)	($0.50)	$1.71	$1.14	$0.72	$0.69	$0.70	$1.27	$0.83	$3.06	$3.48	$4.14

SCHEDULE_I_CONDENSED_FINANCIAL1

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
ASSETS	'	'
Current assets	$1,069,618	$384,412
TOTAL ASSETS	8,833,470	7,272,419
LIABILITIES AND SHAREHOLDERS' EQUITY	'	'
Current liabilities	777,685	636,979
Long-term debt	2,653,834	1,800,000
Other long-term liabilities	4,212	25,852
Shareholders' equity	3,828,567	3,444,988
TOTAL LIABILITIES AND EQUITY	8,833,470	7,272,419
Whiting Petroleum Corporation	'	'
ASSETS	'	'
Current assets	5,120	2,390
Investment in subsidiaries	2,707,184	2,330,987
Intercompany receivable	3,796,321	1,748,463
TOTAL ASSETS	6,508,625	4,081,840
LIABILITIES AND SHAREHOLDERS' EQUITY	'	'
Current liabilities	26,054	14,372
Long-term debt	2,653,834	600,000
Other long-term liabilities	170	21,244
Shareholders' equity	3,828,567	3,446,224
TOTAL LIABILITIES AND EQUITY	$6,508,625	$4,081,840

SCHEDULE_I_CONDENSED_FINANCIAL2

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating expenses:	'	'	'
General and administrative	($137,994)	($108,573)	($84,985)
Interest expense	-112,936	-75,210	-62,516
INCOME BEFORE INCOME TAXES	571,871	662,011	780,319
Income tax benefit	-205,868	-247,912	-288,691
NET INCOME AVAILABLE TO SHAREHOLDERS	366,055	414,189	491,687
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING	367,291	412,713	486,159
Whiting Petroleum Corporation	'	'	'
Operating expenses:	'	'	'
General and administrative	-1,131	-16,506	-12,024
Interest expense	-2,922	-2,168	-2,066
Equity in earnings of subsidiaries	361,732	425,870	500,564
INCOME BEFORE INCOME TAXES	357,679	407,196	486,474
Income tax benefit	8,376	6,993	5,213
NET INCOME AVAILABLE TO SHAREHOLDERS	366,055	414,189	491,687
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING	$366,055	$414,189	$491,687

SCHEDULE_I_CONDENSED_FINANCIAL3

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Details 3) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Oct. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

5% Senior Notes due 2019

5.75% Senior Notes due 2021

7% Senior Subordinated Notes due 2014

7% Senior Subordinated Notes due 2014

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

5% Senior Notes due 2019

5.75% Senior Notes due 2021

7% Senior Subordinated Notes due 2014

Condensed Statements of Cash Flow

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash flows provided by operating activities

$1,744,745

$1,401,215

$1,192,083

'

'

'

'

'

$16,423

$4,962

'

'

'

Cash flows from financing activities:

'

'

'

'

'

'

'

'

'

'

'

'

'

Intercompany receivable

'

'

'

'

'

'

'

-2,048,253

-14,094

-3,091

'

'

'

Issuance of debt

'

'

'

1,100,000

1,204,000

'

'

'

'

'

1,100,000

1,204,000

'

Redemption of 7% Senior Subordinated Notes due 2014

'

'

'

'

'

-254,000

-253,988

'

'

'

'

'

-253,988

Other financing activities

'

'

'

'

'

'

'

-1,759

-2,329

-1,871

'

'

'

Net cash provided by financing activities

812,414

408,092

564,812

'

'

'

'

'

-16,423

-4,962

'

'

'

NONCASH INVESTING ACTIVITIES:

'

'

'

'

'

'

'

'

'

'

'

'

'

Distributions from Whiting USA Trust I decreasing investment in subsidiaries

'

'

'

'

'

'

'

-4,749

-5,827

-6,500

'

'

'

NONCASH FINANCING ACTIVITIES:

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock dividends paid decreasing shareholders' equity

'

'

'

'

'

'

'

-538

-1,077

-1,077

'

'

'

Preferred stock dividends paid decreasing intercompany receivable

'

'

'

'

'

'

'

-538

-1,077

-1,077

'

'

'

Distributions from Whiting USA Trust I increasing intercompany receivable

'

'

'

'

'

'

'

$4,749

$5,827

$6,500

'

'

'

SCHEDULE_I_CONDENSED_FINANCIAL4

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Details 4) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2013

Feb. 22, 2011

Dec. 31, 2013

Dec. 31, 2011

31-May-11

Jun. 30, 2009

Dec. 31, 2012

Dec. 31, 2013

Mar. 31, 2013

Feb. 22, 2011

Dec. 31, 2013

Dec. 31, 2013

Sep. 30, 2010

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Sep. 26, 2013

Dec. 31, 2013

Dec. 31, 2012

Feb. 22, 2011

Dec. 31, 2013

31-May-11

Mar. 31, 2013

Jun. 30, 2009

Dec. 31, 2013

Feb. 22, 2011

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Common Stock

Common Stock

Common Stock

Common Stock

Common Stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

7% Senior Subordinated Notes due 2014

6.5% Senior Subordinated Notes due 2018

6.5% Senior Subordinated Notes due 2018

5% Senior Notes due 2019

5% Senior Notes due 2019

5.75% Senior Notes due 2021

5.75% Senior Notes due 2021

5.75% Senior Notes due 2021

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Whiting Petroleum Corporation

Common Stock

Common Stock

Common Stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

Convertible perpetual preferred stock

7% Senior Subordinated Notes due 2014

6.5% Senior Subordinated Notes due 2018

6.5% Senior Subordinated Notes due 2018

5% Senior Notes due 2019

5.75% Senior Notes due 2021

Parent Company Disclosures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restricted net assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$4,070,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt

2,653,834,000

1,800,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,653,834,000

600,000,000

'

'

'

'

'

'

'

250,000,000

350,000,000

350,000,000

1,100,000,000

1,203,834,000

Interest rate on debt instrument (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

7.00%

6.50%

6.50%

5.00%

5.00%

5.75%

5.75%

5.75%

'

'

'

'

'

'

'

'

'

7.00%

6.50%

'

5.00%

5.75%

Amortization of debt issuance costs and debt premium

12,405,000

9,518,000

8,682,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,834,000

Other long-term liabilities:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Tax sharing liability

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

21,074,000

'

'

'

'

'

'

'

'

'

'

'

'

Other

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

170,000

170,000

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt and other long-term liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,654,004,000

621,244,000

'

'

'

'

'

'

'

'

'

'

'

'

Current liability due to Alliant Energy under tax sharing agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, by Maturity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,856,000

'

'

'

'

'

'

'

'

'

'

'

'

'

2018

350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Thereafter

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt and other long-term liabilities (including current portions)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$2,673,856,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Stockholders equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Authorized shares of common stock

300,000,000

300,000,000

'

'

'

300,000,000

'

175,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000,000

175,000,000

'

'

'

'

'

'

'

'

'

Stock split approved

'

'

2

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

Shares received in stock split for each share held

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

Convertible perpetual preferred stock (as a percent)

'

'

'

'

'

'

'

'

6.25%

6.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.25%

'

'

'

'

'

'

'

Conversion price (in dollars per share)

'

'

'

'

'

'

'

'

$43.42

'

'

'

$21.71

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$43.42

'

$21.71

'

'

'

'

'

6.25% convertible perpetual preferred stock, shares issued

'

'

'

'

'

'

'

'

3,450,000

172,391

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,450,000

'

'

'

'

'

'

'

6.25% convertible perpetual preferred stock, shares issue Price per share (in dollars per share)

'

'

'

'

'

'

'

'

$100

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$100

'

'

'

'

'

'

'

Preferred stock remained outstanding

'

'

'

'

'

'

'

'

'

172,391

0

172,129

'

'

'

'

'

'

'

'

'

'

'

'

'

'

172,129

'

0

'

'

'

'

'

'

Conversion of preferred stock to common (in shares)

'

'

'

792,919

'

794,000

1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

792,919

'

'

'

'

'

'

'

'