10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2012

or

[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________ to _______________

		Commission file number:  001-31899 WHITING PETROLEUM CORPORATION
		(Exact name of registrant as specified in its charter)
Delaware			20-0098515
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)
1700 Broadway, Suite 2300 Denver, Colorado			80290-2300
(Address of principal executive offices)			(Zip code)
	(303) 837-1661
	(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  TNo  £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  TNo  £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filerT Accelerated filer    £ Non-accelerated filer£ Smaller reporting company   £

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).       Yes£NoT

Number of shares of the registrant’s common stock outstanding at April 15, 2012:  117,617,777 shares.

	TABLE OF CONTENTS
Glossary of Certain Definitions		1
	PART I – FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements (Unaudited)	3
	Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011	3
	Consolidated Statements of Income for the Three Months Ended March 31, 2012 and 2011	4
	Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2012 and 2011	5
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011	6
	Consolidated Statements of Equity for the Three Months Ended March 31, 2012 and 2011	8
	Notes to Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosure About Market Risk	37
Item 4.	Controls and Procedures	39
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
	Certification by the Chairman and Chief Executive Officer
	Certification by the Vice President and Chief Financial Officer
	Written Statement of the Chairman and Chief Executive Officer
	Written Statement of the Vice President and Chief Financial Officer

GLOSSARY OF CERTAIN DEFINITIONS

Unless the context otherwise requires, the terms “we,” “us,” “our” or “ours” when used in this report refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries.  When the context requires, we refer to these entities separately.

We have included below the definitions for certain terms used in this report:

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil and other liquid hydrocarbons.

“Bcf” One billion cubic feet of natural gas.

“BOE” One stock tank barrel equivalent of oil, calculated by converting natural gas volumes to equivalent oil barrels at a ratio of six Mcf to one Bbl of oil.

“EBITDAX” Earnings before interest, income taxes, depreciation, depletion, amortization and exploration expense.

“FASB” Financial Accounting Standards Board.

“FASB ASC” The Financial Accounting Standards Board Accounting Standards Codification.

“GAAP” Generally accepted accounting principles in the United States of America.

“MBbl” One thousand barrels of oil or other liquid hydrocarbons.

“MBOE” One thousand BOE.

“MBOE/d” One MBOE per day.

“Mcf” One thousand cubic feet of natural gas.

“MMBbl” One million Bbl.

“MMBOE” One million BOE.

“MMBtu” One million British Thermal Units.

“MMcf” One million cubic feet of natural gas.

“MMcf/d” One MMcf per day.

“plugging and abandonment” Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.  Regulations of many states require plugging of abandoned wells.

1

“proved reserves” Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir considered as proved includes all of the following:

a.   The area identified by drilling and limited by fluid contacts, if any, and

b.   Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

a.   Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

b.   The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.  The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“working interest” The interest in a crude oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

2

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements

WHITING PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share data)

	March 31,			December 31,
	2012			2011
ASSETS
Current assets:
Cash and cash equivalents	$	9,825		$	15,811
Accounts receivable trade, net		293,863			262,515
Prepaid expenses and other		24,691			20,377
Total current assets		328,379			298,703
Property and equipment:
Oil and gas properties, successful efforts method:
Proved properties		7,335,250			7,221,550
Unproved properties		372,473			354,774
Other property and equipment		148,524			150,933
Total property and equipment		7,856,247			7,727,257
Less accumulated depreciation, depletion and amortization		(2,070,259	)		(2,088,517	)
Total property and equipment, net		5,785,988			5,638,740
Debt issuance costs		31,504			33,306
Other long-term assets		73,784			74,860
TOTAL ASSETS	$	6,219,655		$	6,045,609
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable trade	$	93,969		$	56,673
Accrued capital expenditures		121,969			142,827
Accrued liabilities and other		169,915			157,214
Revenues and royalties payable		119,567			103,894
Taxes payable		36,113			31,195
Derivative liabilities		87,960			73,647
Deferred income taxes		4,855			1,584
Total current liabilities		634,348			567,034
Long-term debt		1,240,000			1,380,000
Deferred income taxes		877,530			823,643
Derivative liabilities		43,646			47,763
Production Participation Plan liability		81,594			80,659
Asset retirement obligations		54,988			61,984
Deferred gain on sale		135,971			29,619
Other long-term liabilities		26,396			25,776
Total liabilities		3,094,473			3,016,478
Commitments and contingencies
Equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible perpetual preferred stock, 172,391 shares issued and outstanding as of March 31, 2012 and December 31, 2011, aggregate liquidation preference of $17,239,100 at March 31, 2012		-			-
Common stock, $0.001 par value, 300,000,000 shares authorized; 118,565,350 issued and 117,617,777 outstanding as of March 31, 2012, 118,105,279 issued and 117,380,884 outstanding as of December 31, 2011		119			118
Additional paid-in capital		1,552,808			1,554,223
Accumulated other comprehensive income (loss)		(472	)		240
Retained earnings		1,564,477			1,466,276
Total Whiting shareholders’ equity		3,116,932			3,020,857
Noncontrolling interest		8,250			8,274
Total equity		3,125,182			3,029,131
TOTAL LIABILITIES AND EQUITY	$	6,219,655		$	6,045,609
See notes to consolidated financial statements.

3

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(In thousands, except per share data)

	Three Months Ended March 31,
	2012			2011
REVENUES AND OTHER INCOME:
Oil and natural gas sales	$	558,697		$	425,683
Gain on hedging activities		1,127			3,063
Amortization of deferred gain on sale		3,753			3,367
Interest income and other		129			108
Total revenues and other income		563,706			432,221
COSTS AND EXPENSES:
Lease operating		94,790			71,522
Production taxes		44,611			31,644
Depreciation, depletion and amortization		156,120			107,728
Exploration and impairment		27,578			22,237
General and administrative		34,368			18,413
Interest expense		18,456			14,458
Change in Production Participation Plan liability		935			(443	)
Commodity derivative loss, net		29,403			134,438
Total costs and expenses		406,261			399,997
INCOME BEFORE INCOME TAXES		157,445			32,224
INCOME TAX EXPENSE:
Current		1,426			2,050
Deferred		57,573			10,760
Total income tax expense		58,999			12,810
NET INCOME		98,446			19,414
Net loss attributable to noncontrolling interest		24			-
NET INCOME AVAILABLE TO SHAREHOLDERS		98,470			19,414
Preferred stock dividends		(269	)		(270	)
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$	98,201		$	19,144
EARNINGS PER COMMON SHARE:
Basic	$	0.84		$	0.16
Diluted	$	0.83		$	0.16
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		117,517			117,243
Diluted		118,896			117,834
See notes to consolidated financial statements.

4

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(In thousands)

	Three Months Ended March 31,
	2012			2011
NET INCOME	$	98,446		$	19,414
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
OCI amortization on de-designated hedges(1)		(712	)		(1,934	)
Total other comprehensive loss, net of tax		(712	)		(1,934	)
COMPREHENSIVE INCOME		97,734			17,480
Comprehensive loss attributable to noncontrolling interest		24			-
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING	$	97,758		$	17,480
(1) Presented net of income tax expense of $415 and $1,130 for the three months ended March 31, 2012 and 2011, respectively.

5

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Three Months Ended March 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	98,446		$	19,414
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		156,120			107,728
Deferred income tax expense		57,573			10,760
Amortization of debt issuance costs and debt discount		2,340			2,127
Stock-based compensation		4,243			3,164
Amortization of deferred gain on sale		(3,753	)		(3,367	)
Undeveloped leasehold and oil and gas property impairments		17,834			7,638
Exploratory dry hole costs		251			2,902
Change in Production Participation Plan liability		935			(443	)
Unrealized loss on derivative contracts		14,546			123,545
Other non-current		(5,853	)		(815	)
Changes in current assets and liabilities:
Accounts receivable trade		(31,348	)		(44,303	)
Prepaid expenses and other		(5,431	)		(7,861	)
Accounts payable trade and accrued liabilities		26,498			3,708
Revenues and royalties payable		15,673			(6,534	)
Taxes payable		4,918			(3,608	)
Net cash provided by operating activities		352,992			214,055
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash acquisition capital expenditures		(46,738	)		(91,525	)
Drilling and development capital expenditures		(492,810	)		(284,752	)
Proceeds from sale of oil and gas properties		2,922			21
Issuance of note receivable		-			(25,000	)
Net proceeds from sale of 18,400,000 units in Whiting USA Trust II		323,574			-
Net cash used in investing activities		(213,052	)		(401,256	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Contributions from noncontrolling interest		-			2,500
Preferred stock dividends paid		(269	)		(270	)
Long-term borrowings under credit agreement		520,000			470,000
Repayments of long-term borrowings under credit agreement		(660,000	)		(290,000	)
Debt issuance costs		-			(11	)
Restricted stock used for tax withholdings		(5,657	)		(8,944	)
Net cash provided by (used in) financing activities		(145,926	)		173,275
NET CHANGE IN CASH AND CASH EQUIVALENTS		(5,986	)		(13,926	)
CASH AND CASH EQUIVALENTS:
Beginning of period		15,811			18,952
End of period	$	9,825		$	5,026
See notes to consolidated financial statements.				(Continued)

6

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)

	Three Months Ended March 31,
	2012		2011
NONCASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	121,969	$	97,274
NONCASH FINANCING ACTIVITIES:
Contributions from noncontrolling interest	$	-	$	5,833
See notes to consolidated financial statements.			(Concluded)

7

WHITING PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY (Unaudited)

(In thousands)

	Preferred Stock					Common Stock					Additional Paid-			Accumulated Other Comprehensive			Retained			Total Whiting Shareholders’			Noncontrolling
	Shares			Amount		Shares			Amount		in Capital			Income (Loss)			Earnings			Equity			Interests			Total Equity
BALANCES-January 1, 2011		173		$	-		117,968		$	59	$	1,549,822		$	5,768		$	975,666		$	2,531,315		$	-		$	2,531,315
Net income		-			-		-			-		-			-			19,414			19,414			-			19,414
OCI amortization on de-designated hedges, net of taxes of $1,130		-			-		-			-		-			(1,934	)		-			(1,934	)		-			(1,934	)
Conversion of preferred stock to common		(1	)		-		1			-		-			-			-			-			-			-
Two-for-one stock split		-			-		-			59		(59	)		-			-			-			-			-
Contributions from noncontrolling interest		-			-		-			-		-			-			-			-			8,333			8,333
Restricted stock issued		-			-		293			-		-			-			-			-			-			-
Restricted stock forfeited		-			-		(3	)		-		-			-			-			-			-			-
Restricted stock used for tax withholdings		-			-		(147	)		-		(8,944	)		-			-			(8,944	)		-			(8,944	)
Stock-based compensation		-			-		-			-		3,164			-			-			3,164			-			3,164
Preferred dividends paid		-			-		-			-		-			-			(270	)		(270	)		-			(270	)
BALANCES-March 31, 2011		172		$	-		118,112		$	118	$	1,543,983		$	3,834		$	994,810		$	2,542,745		$	8,333		$	2,551,078
BALANCES-January 1, 2012		172		$	-		118,105		$	118	$	1,554,223		$	240		$	1,466,276		$	3,020,857		$	8,274		$	3,029,131
Net income		-			-		-			-		-			-			98,470			98,470			(24	)		98,446
OCI amortization on de-designated hedges, net of taxes of $415		-			-		-			-		-			(712	)		-			(712	)		-			(712	)
Restricted stock issued		-			-		569			1		(1	)		-			-			-			-			-
Restricted stock forfeited		-			-		(3	)		-		-			-			-			-			-			-
Restricted stock used for tax withholdings		-			-		(106	)		-		(5,657	)		-			-			(5,657	)		-			(5,657	)
Stock-based compensation		-			-		-			-		4,243			-			-			4,243			-			4,243
Preferred dividends paid		-			-		-			-		-			-			(269	)		(269	)		-			(269	)
BALANCES-March 31, 2012		172		$	-		118,565		$	119	$	1,552,808		$	(472	)	$	1,564,477		$	3,116,932		$	8,250		$	3,125,182
See notes to consolidated financial statements.

8

WHITING PETROLEUM CORPORATION

NOTES TO CONSOLIDATED

FINANCIAL STATEMENTS (Unaudited)

1.   BASIS OF PRESENTATION

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, natural gas and natural gas liquids primarily in the Rocky Mountains, Permian Basin, Mid-Continent, Michigan and Gulf Coast 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.

Consolidated Financial Statements—The unaudited 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.  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.  These financial statements have been prepared in accordance with GAAP for interim financial reporting.  In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results.  However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.  Whiting’s 2011 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q.  Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in Whiting’s 2011 Annual Report on Form 10-K.

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.

2.   ACQUISITIONS AND DIVESTITURES

2012 Acquisitions

On March 22, 2012, the Company completed the acquisition of approximately 13,300 net undeveloped acres in the Missouri Breaks prospect in Richland County, Montana for $33.3 million.

9

2012 Divestitures

On March 28, 2012, the Company completed an initial public offering of units of beneficial interest in Whiting USA Trust II (“Trust II”), selling 18,400,000 Trust II units at $20.00 per unit, providing net proceeds of $323.6 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 $129.5 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 18,400,000 trust 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.  The conveyance of the net profits interest to Trust II consisted entirely of proved reserves of 10.61 MMBOE as of the January 1, 2012 effective date, representing 3% of Whiting’s proved reserves as of December 31, 2011 and 5% (or 4.5 MBOE/d) of its March 2012 average daily net production.

2011 Acquisitions

On July 28, 2011, the Company completed the acquisition of approximately 23,400 net acres and one well in the Missouri Breaks prospect 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.

3.   LONG-TERM DEBT

Long-term debt consisted of the following at March 31, 2012 and December 31, 2011 (in thousands):

10

	March 31, 2012		December 31, 2011
Credit agreement	$	640,000	$	780,000
6.5% Senior Subordinated Notes due 2018		350,000		350,000
7% Senior Subordinated Notes due 2014		250,000		250,000
Total debt	$	1,240,000	$	1,380,000

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.  As of March 31, 2012, this credit facility had a borrowing base of $1.5 billion with $858.6 million of available borrowing capacity, which is net of $640.0 million in borrowings and $1.4 million in letters of credit 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 its 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 March 31, 2012, $48.6 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 are included as a component of interest expense.  At March 31, 2012, the weighted average interest rate on the outstanding principal balance under the credit agreement was 2.1%.

Ratio of Outstanding Borrowings to Borrowing Base	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 0.25 to 1.0	0.50%	1.50%	0.375%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0	0.75%	1.75%	0.375%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0	1.00%	2.00%	0.50%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0	1.25%	2.25%	0.50%
Greater than or equal to 0.90 to 1.0	1.50%	2.50%	0.50%

The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders.  Except for limited exceptions, which include the payment of dividends on the Company’s 6.25% convertible perpetual preferred stock, the credit agreement also restricts our 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 March 31, 2012, total restricted net assets were $2,961.0 million, and the amount of retained earnings free from restrictions was $17.8 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 4.25 to 1.0 for quarters ending prior to and on December 31, 2012 and 4.0 to 1.0 for quarters ending March 31, 2013 and thereafter 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 March 31, 2012.

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The obligations of Whiting Oil and Gas under the amended 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 Subordinated Notes—In October 2005, the Company issued at par $250.0 million of 7% Senior Subordinated Notes due February 2014.  The estimated fair value of these notes was $266.9 million as of March 31, 2012, based on quoted market prices for these same debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy.

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 $372.3 million as of March 31, 2012, based on quoted market prices for these same debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy.

The notes are unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the Company’s senior debt, which currently consists of Whiting Oil and Gas’ credit agreement.  The Company’s obligations under the 2014 notes are fully, unconditionally, jointly and severally guaranteed by the Company’s 100%-owned subsidiaries, Whiting Oil and Gas and Whiting Programs, Inc. (the “2014 Guarantors”).  Additionally, the Company’s obligations under the 2018 notes are fully, unconditionally, jointly and severally guaranteed by the Company’s 100%-owned subsidiary, Whiting Oil and Gas (collectively with the 2014 Guarantors, the “Guarantors”).  Any subsidiaries other than the Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S-X of the Securities and Exchange Commission.  Whiting Petroleum Corporation has no assets or operations independent of this debt and its investments in guarantor subsidiaries.

4.   ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations represent the 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 March 31, 2012 and December 31, 2011 were $11.8 million and $7.7 million, respectively, and are included in accrued liabilities and other.  Revisions to the liability could 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 three months ended March 31, 2012 (in thousands):

Asset retirement obligation at January 1, 2012	$	69,721
Additional liability incurred		1,342
Revisions in estimated cash flows		(3,195	)
Accretion expense		1,907
Obligations on sold properties		(4	)
Liabilities settled		(2,983	)
Asset retirement obligation at March 31, 2012	$	66,788

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5.   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, 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 and 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 I and Trust II derivatives, entered into to hedge forecasted crude oil and natural gas production revenues, as of April 1, 2012.

	Whiting Petroleum Corporation
	Contracted Volumes		Weighted Average NYMEX Price Collar Ranges
Period	Crude Oil (Bbl)	Natural Gas (Mcf)	Crude Oil (per Bbl)	Natural Gas (per Mcf)
Apr – Dec 2012	8,895,860	283,858	$66.71 - $108.62	$6.32 - $13.82
Jan – Dec 2013	3,143,700	-	$48.20 - $ 90.45	n/a
Jan – Dec 2014	49,290	-	$80.00 - $122.50	n/a
Total	12,088,850	283,858

Derivatives Conveyed to Whiting USA Trust I.  In connection with the Company’s conveyance in April 2008 of a term net profits interest to Trust I and related sale of 11,677,500 Trust I 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 I, and therefore such payments will be included in Trust I’s calculation of net proceeds.  Under the terms of the aforementioned conveyance, Whiting retains 10% of the net proceeds from the underlying properties.  Whiting’s retention of 10% of these net proceeds, combined with its ownership of 2,186,389 Trust I units, results in third-party public holders of Trust I units receiving 75.8%, and Whiting retaining 24.2%, of the future economic results of commodity derivative contracts conveyed to Trust I.  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 I assets.

The 24.2% portion of Trust I derivatives that Whiting has retained the economic rights to (and which are also included in the table above) are as follows:

	Whiting Petroleum Corporation
	Contracted Volumes		Weighted Average NYMEX Price Collar Ranges
Period	Crude Oil (Bbl)	Natural Gas (Mcf)	Crude Oil (per Bbl)	Natural Gas (per Mcf)
Apr – Dec 2012	77,930	283,858	$74.00 - $141.87	$6.32 - $13.82

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The 75.8% portion of Trust I derivative contracts of which Whiting has transferred the economic rights to third-party public holders of Trust I units (and which have not been reflected in the above tables) are as follows:

	Third-party Public Holders of Trust I Units
	Contracted Volumes		Weighted Average NYMEX Price Collar Ranges
Period	Crude Oil (Bbl)	Natural Gas (Mcf)	Crude Oil (per Bbl)	Natural Gas (per Mcf)
Apr – Dec 2012	244,096	889,109	$74.00 - $141.87	$6.32 - $13.82

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
	Contracted Crude Oil Volumes (Bbl)	Weighted Average NYMEX Price Collar Ranges for Crude Oil (per Bbl)
Apr – Dec 2012	42,930	$80.00 - $122.50
Jan – Dec 2013	53,700	$80.00 - $122.50
Jan – Dec 2014	49,290	$80.00 - $122.50
	145,920

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
	Contracted Crude Oil Volumes (Bbl)	Weighted Average NYMEX Price Collar Ranges for Crude Oil (per Bbl)
Apr – Dec 2012	386,370	$80.00 - $122.50
Jan – Dec 2013	483,300	$80.00 - $122.50
Jan – Dec 2014	443,610	$80.00 - $122.50
	1,313,280

Embedded Commodity Derivative Contracts—As of March 31, 2012, Whiting had entered into certain contracts for oil field goods or services, whereby the price adjustment clauses for such goods or services are linked to changes in NYMEX crude oil prices.  The Company has determined that the portions of these contracts linked to NYMEX oil prices are not clearly and closely related to the host contracts, and the Company has therefore bifurcated these embedded pricing features from their host contracts and reflected them at fair value in the consolidated financial statements.

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Drilling Rig Contracts.  As of March 31, 2012, Whiting had entered into two contracts with drilling rig companies, whereby the rig day rates included price adjustment clauses that are linked to changes in NYMEX crude oil prices.  These drilling rig contracts have termination dates of March 2014 and September 2014.  The price adjustment formulas in the rig contracts stipulate that with every $10 increase or decrease in the price of NYMEX crude, the cost of drilling rig day rates to the Company will likewise increase or decrease by specific dollar amounts as set forth in each of the individual contracts.  As of March 31, 2012, the aggregate estimated fair value of the embedded derivatives in these drilling rig contracts was a liability of $0.8 million.

As global crude oil prices increase or decrease, the demand for drilling rigs in North America similarly increases and decreases.  Because the supply of onshore drilling rigs in North America is fairly inelastic, these changes in rig demand cause drilling rig day rates to increase or decrease in tandem with crude oil price fluctuations.  When the Company enters into a long-term drilling rig contract that has a fixed rig day rate, which does not increase or decrease with changes in oil prices, the Company is exposed to the risk of paying higher than the market day rate for drilling rigs in a climate of declining oil prices.  This in turn could have a negative impact on the Company’s oil and gas well economics.  As a result, the Company reduces its exposure to this risk by entering into certain drilling contracts which have day rates that fluctuate in tandem with changes in oil prices.

CO2 Purchase 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.  The price per Mcf of CO2 purchased under this agreement increases or decreases as the average price of NYMEX crude oil likewise increases or decreases.  As of March 31, 2012, the estimated fair value of the embedded derivative in this CO2 purchase contract was an asset of $8.9 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 on the consolidated balance sheet at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion.  The following tables summarize the location and fair value amounts of all derivative instruments in the consolidated balance sheets (in thousands):

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		Fair Value
Not Designated as ASC 815 Hedges	Balance Sheet Classification	March 31,  2012		December 31,  2011
Derivative assets:
Commodity contracts	Prepaid expenses and other	$	4,850	$	5,719
Embedded commodity contracts	Prepaid expenses and other		-		240
Commodity contracts	Other long-term assets		242		-
Embedded commodity contracts	Other long-term assets		8,866		13,347
Total derivative assets		$	13,958	$	19,306
Derivative liabilities:
Commodity contracts	Current derivative liabilities	$	87,517	$	73,647
Embedded commodity contracts	Current derivative liabilities		443		-
Commodity contracts	Non-current derivative liabilities		43,243		47,763
Embedded commodity contracts	Non-current derivative liabilities		403		-
Total derivative liabilities		$	131,606	$	121,410

The following tables summarize the effects of commodity derivatives instruments on the consolidated statements of income for the three months ended March 31, 2012 and 2011 (in thousands):

		Gain Reclassified from OCI into Income (Effective Portion)
ASC 815 Cash Flow		Three Months Ended March 31,
Hedging Relationships	Income Statement Classification	2012		2011
Commodity contracts	Gain on hedging activities	$	1,127	$	3,063

		Loss Recognized in Income
Not Designated as		Three Months Ended March 31,
ASC 815 Hedges	Income Statement Classification	2012		2011
Commodity contracts	Commodity derivative loss, net	$	23,837	$	131,357
Embedded commodity contracts	Commodity derivative loss, net		5,566		3,081
Total		$	29,403	$	134,438

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 current or former lenders under Whiting’s credit agreement.  At the time Whiting enters into derivative contracts, 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.

6.   FAIR VALUE MEASURMENTS

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.

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·   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 March 31, 2012 and December 31, 2011, 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 March 31, 2012
Financial Assets
Commodity derivatives – current	$	-	$	4,850	$	-	$	4,850
Commodity derivatives – non-current		-		242		-		242
Embedded commodity derivatives – non-current		-		-		8,866		8,866
Total financial assets	$	-	$	5,092	$	8,866	$	13,958
Financial Liabilities
Commodity derivatives – current	$	-	$	87,517	$	-	$	87,517
Embedded commodity derivatives – current				443		-		443
Commodity derivatives – non-current		-		43,243		-		43,243
Embedded commodity derivatives – non-current				403		-		403
Total financial liabilities	$	-	$	131,606	$	-	$	131,606

	Level 1		Level 2		Level 3		Total Fair Value December 31, 2011
Financial Assets
Commodity derivatives – current	$	-	$	5,719	$	-	$	5,719
Embedded commodity derivatives – current		-		240		-		240
Embedded commodity derivatives – non-current		-		367		12,980		13,347
Total financial assets	$	-	$	6,326	$	12,980	$	19,306
Financial Liabilities
Commodity derivatives – current	$	-	$	73,647	$	-	$	73,647
Commodity derivatives – non-current		-		47,763		-		47,763
Total financial liabilities	$	-	$	121,410	$	-	$	121,410

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

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Commodity Derivatives.  Commodity derivative instruments consist primarily of costless collars for crude oil and natural gas.  The Company’s costless collars are valued based on an income approach.  These option models consider various assumptions, including 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 counterparties’ valuations to assess the reasonableness of its own valuations.

Embedded Commodity Derivatives.  Embedded commodity derivatives relate to long-term drilling rig contracts as well as a long-term CO2 purchase contract, which all have price adjustment clauses that are linked to changes in NYMEX crude oil prices.  Whiting has determined that the portions of these contracts linked to NYMEX oil prices are not clearly and closely related to the host drilling contracts, and the Company has therefore bifurcated these embedded pricing features from their host contracts and reflected them at fair value in its consolidated financial statements.  These embedded commodity derivatives are valued based on an income approach.  These option models consider 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 valuation of the drilling rig contracts 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 the fair value measurements of the drilling rig contracts are therefore designated as Level 2 within the valuation hierarchy.

The assumptions used in the CO2 contract valuation, however, 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 thecontract’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 to determine the fair value of the embedded commodity derivative instrument designated as Level 3.  The Company reviews these valuations (including the related model inputs and assumptions) and analyzes changes in fair value measurements between periods.  The Company corroborates such inputs, calculations and fair value changes using various methodologies.

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 three months ended March 31, 2012 (in thousands):

	Three Months Ended
	March 31, 2012(2)
Fair value asset, beginning of period	$	12,980
Unrealized gains (losses) on embedded commodity derivative contracts included in earnings(1)		(4,114	)
Transfers into (out of) Level 3		-
Fair value asset, end of period	$	8,866

_____________________

(1)   Included in commodity derivative loss, net in the consolidated statements of income.

(2)   There were no recurring fair value measurements designated as Level 3 during the three months ended March 31, 2011.

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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 March 31, 2012 (in thousands)		Valuation Technique	Unobservable Input	Range (per Bbl)
Embedded commodity derivative	$	8,866	Option model	Future prices of NYMEX crude oil after December 31, 2017	$93.81 - $122.98

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 2018 to 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.  These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances.  The Company did not recognize any nonrecurring fair value adjustments during the 2012 or 2011 reporting periods presented.

7.   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 2%-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 three months ended March 31, 2012 and 2011 amounted to $18.9 million and $8.0 million, respectively, charged to general and administrative expense and $2.0 million and $0.9 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 March 31, 2012, the Company used three-year average historical NYMEX prices of $82.50 for crude oil and $4.01 for natural gas to estimate this liability.  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 March 31, 2012, 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 $167.6 million.  This amount includes $15.0 million attributable to proved undeveloped oil and gas properties and $20.9 million relating to the short-term portion of the Plan liability, which has been accrued as a current payable to be paid in February 2013.  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.

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The following table presents changes in the Plan’s estimated long-term liability (in thousands):

Long-term Production Participation Plan liability at January 1	$	80,659
Change in liability for accretion, vesting, changes in estimates and new Plan year activity		21,815
Cash payments accrued as compensation expense and reflected as a current payable		(20,880	)
Long-term Production Participation Plan liability at March 31	$	81,594

8.    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 of March 31, 2012, however, only 172,391 shares of preferred stock remained outstanding.

Each holder of the preferred stock is 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 has been declared by Whiting’s board of directors.  Each share of preferred stock has a liquidation preference of $100.00 per share plus accumulated and unpaid dividends and is convertible, at a holder’s option, into shares of Whiting’s common stock based on a conversion price of $21.70815, subject to adjustment upon the occurrence of certain events.  The preferred stock is not redeemable by the Company.  At any time on or after June 15, 2013, the Company may cause all outstanding shares of this preferred stock to be converted into shares of common stock if the closing price of our common stock equals or exceeds 120% of the then-prevailing conversion price for at least 20 trading days in a period of 30 consecutive trading days.  The holders of preferred stock have no voting rights unless dividends payable on the preferred stock are in arrears for six or more quarterly periods.

Equity Incentive Plan—The Company maintains the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “Equity Plan”), pursuant to which 2,978,323 shares of the Company’s common stock have been reserved for issuance.  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 March 31, 2012, 1,066,089 shares of common stock remained available for grant under the Plan.

For the three months ended March 31, 2012 and 2011, total stock compensation expense recognized for restricted share awards and stock options was $4.2 million and $3.2 million, respectively.

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Restricted Shares.  Restricted stock awards for executive officers, directors and employees generally vest ratably over a three-year service period.  The Company uses historical data and projections to estimate expected employee behaviors related to restricted stock forfeitures.  The expected forfeitures are then included as part of the grant date estimate of compensation cost.  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 2012 and 2011, 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:

	2012	2011
Number of simulations	65,000	65,000
Expected volatility	51.9%	75.8%
Risk-free rate	0.35%	1.00%

The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation model was $29.45 per share in January 2012 and $42.20 per share in January 2011.

The following table shows a summary of the Company’s nonvested restricted stock as of March 31, 2012 as well as activity during the three months then ended:

	Number of Shares		Weighted Average Grant Date Fair Value
Restricted stock awards nonvested, January 1, 2012	724,395		$	29.88
Granted	568,661			34.20
Vested	(342,556	)		16.92
Forfeited	(2,927	)		51.59
Restricted stock awards nonvested, March 31, 2012	947,573		$	37.09

As of March 31, 2012, there was $22.5 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 2.6 years.

Stock Options.  In January 2012 and 2011, 45,358 stock options and 80,820 stock options, respectively, were granted under the 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.  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.

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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 period:

	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 in January 2012 and $34.15 per share in January 2011.

The following table shows a summary of the Company’s stock options outstanding as of March 31, 2012 as well as activity during the three months then ended (aggregate intrinsic value presented in thousands):

	Number of Options		Weighted Average Exercise Price per Share		Aggregate Intrinsic Value		Weighted Average Remaining Contractual Term (in Years)
Options outstanding at January 1, 2012		377,336	$	26.09
Granted		45,358		51.22
Exercised		-		-	$	-
Forfeited or expired		-		-
Options outstanding at March 31, 2012		422,694	$	28.79	$	11,265.2		7.7
Options vested and expected to vest at March 31, 2012		422,694	$	28.79	$	11,265.2		7.7
Options exercisable at March 31, 2012		305,022	$	19.56	$	10,757.0		7.2

Unrecognized compensation cost as of March 31, 2012 related to unvested stock option awards was $2.2 million, which is expected to be recognized over a period of 2.3 years.

Noncontrolling Interest—The noncontrolling interest represents an unrelated third party’s 25% ownership interest in SWR.  Thetable below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):

	Three Months Ended March 31,
	2012			2011
Balance at January 1	$	8,274		$	-
Contributions from noncontrolling interest		-			8,333
Net income (loss)		(24	)		-
Balance at March 31	$	8,250		$	8,333

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9.   INCOME TAXES

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period.  The provision for income taxes for the three months ended March 31, 2012 and 2011 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to pre-tax income primarily because of state income taxes and estimated permanent differences.

The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent and temporary differences, and the likelihood of recovering deferred tax assets generated in the current year.  The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, additional information becomes known or as the tax environment changes.

10.   EARNINGS PER SHARE

The reconciliations between basic and diluted earnings per share are as follows (in thousands, except per share data):

	Three Months Ended March 31,
	2012			2011
Basic Earnings Per Share
Numerator:
Net income available to shareholders	$	98,470		$	19,414
Preferred stock dividends		(269	)		(270	)
Net income available to common shareholders, basic	$	98,201		$	19,144
Denominator:
Weighted average shares outstanding, basic		117,517			117,243
Diluted Earnings Per Share
Numerator:
Net income available to common shareholders, basic	$	98,201		$	19,144
Preferred stock dividends		269			-
Adjusted net income available to common shareholders, diluted	$	98,470		$	19,144
Denominator:
Weighted average shares outstanding, basic		117,517			117,243
Restricted stock and stock options		585			591
Convertible perpetual preferred stock		794			-
Weighted average shares outstanding, diluted		118,896			117,834
Earnings per common share, basic	$	0.84		$	0.16
Earnings per common share, diluted	$	0.83		$	0.16

For the three months ended March 31, 2012, the diluted earnings per share calculation excludes the effect of 7,006 common shares for stock options that were out-of-the-money.  For the three months ended March 31, 2011, the diluted earnings per share calculation excludes the effect of 794,330 incremental common shares (which were issuable upon the conversion of perpetual preferred stock as of a January 1, 2011 assumed conversion date) because their effect was anti-dilutive.

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11.   ADOPTED AND RECENTLY ISSUED ACCOUNTING 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.  These amendments are not having a significant impact on companies applying GAAP.  ASU 2011-04 was effective for interim and annual 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 defers 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 previously 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.  ASU 2011-11 is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively.  The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours” when used in this Item refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries, Whiting Oil and Gas Corporation and Whiting Programs, Inc.  When the context requires, we refer to these entities separately.  This document contains forward-looking statements, which give our current expectations or forecasts of future events.  Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of these types of statements.

Overview

We are an independent oil and gas company engaged in exploration, development, acquisition and production activities primarily in the Rocky Mountains, Permian Basin, Mid-Continent, Michigan and Gulf Coast regions of the United States.  Prior to 2006, we generally emphasized the acquisition of properties that increased our production levels and provided upside potential through further development.  Since 2006, we have focused primarily on organic drilling activity and on the development of previously acquired properties, specifically on projects that we believe provide the opportunity for repeatable successes and production growth.  We believe the combination of acquisitions, subsequent development and organic drilling provides us a broad set of growth alternatives and allows us to direct our capital resources to what we believe to be the most advantageous investments.

As demonstrated by our recent capital expenditure programs, we are increasingly focused on a balanced exploration and development program, while continuing to selectively pursue acquisitions that complement our existing core properties.  We believe that our significant drilling inventory, combined with our operating experience and cost structure, provides us with meaningful organic growth opportunities.  Our growth plan is centered on the following activities:

• pursuing the development of projects that we believe will generate attractive rates of return;

• maintaining a balanced portfolio of lower risk, long-lived oil and gas properties that provide stable cash flows;

• seeking property acquisitions that complement our core areas; and

• allocating a portion of our capital budget to leasing and exploring prospect areas.

We have historically acquired operated and non-operated properties that exceed our rate of return criteria.  For acquisitions of properties with additional development and exploration potential, our focus has been on acquiring operated properties so that we can better control the timing and implementation of capital spending.  In some instances, we have been able to acquire non-operated property interests at attractive rates of return that established a presence in a new area of interest or that have complemented our existing operations.  We intend to continue to acquire both operated and non-operated interests to the extent we believe they meet our return criteria.  In addition, our willingness to acquire non-operated properties in new geographic regions provides us with geophysical and geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-operated basis.  We sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own.

Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as economic, political and regulatory developments and competition from other sources of energy.  Oil and gas prices historically have been volatile and may fluctuate widely in the future.  The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas prices since the first quarter of 2010:

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	2010				2011				2012
	Q1	Q2	Q3	Q4	Q1	Q2	Q3	Q4	Q1
Crude Oil	$78.79	$77.99	$76.21	$85.18	$94.25	$102.55	$89.81	$94.02	$102.94
Natural Gas	$5.30	$4.09	$4.39	$3.81	$4.10	$4.32	$4.20	$3.54	$2.72

Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our oil and gas reserves.  A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and gas properties and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures.  Lower oil and gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders.  Alternatively, higher oil and natural gas prices may result in significant non-cash, mark-to-market losses being incurred on our commodity-based derivatives, which may in turn cause us to experience net losses.

First Quarter 2012 Highlights and Future Considerations

Operational Highlights.

Lewis & Clark/Pronghorn.  Our Lewis & Clark/Pronghorn prospects are located primarily in the Stark and Billings counties of North Dakota and run along the Bakken shale pinch-out in the southern Williston Basin.  In this area, the Upper Bakken shale is thermally mature, moderately over-pressured, and we believe that it has charged reservoir zones within the immediately underlying Pronghorn Sand and Three Forks formations.  Net production in the Lewis & Clark/Pronghorn prospects averaged 9.1 MBOE/d in the first quarter of 2012, representing a 54% increase from 5.9 MBOE/d in the fourth quarter of 2011.  We currently have five drilling rigs operating in the Pronghorn prospect and one drilling rig operating in the Lewis & Clark prospect.

In December 2011, we completed and commissioned the gas processing plant located south of Belfield, North Dakota, which will have a processing capacity of 30 MMcf/d and which will primarily process production from the Pronghorn area.  Currently there is inlet compression in place to process 24 MMcf/d, and as of March 31, 2012 the plant was processing 7.6 MMcf/d.

Hidden Bench/Tarpon.  Our Hidden Bench and Tarpon prospects in McKenzie County, North Dakota target the Bakken and Three Forks formations.  Net production from the Hidden Bench/Tarpon prospects averaged 2.2 MBOE/d in the first quarter of 2012, which represents a 27% increase from 1.8 MBOE/d in the fourth quarter of 2011.

Sanish.  Our Sanish field in Mountrail County, North Dakota targets the Bakken and Three Forks formations.  Net production in the Sanish field averaged 28.8 MBOE/d for the first quarter of 2012, representing a 26% increase from 22.9 MBOE/d in the fourth quarter of 2011.  During the first quarter of 2012, we completed 15 operated wells, bringing the total number of producing wells in the field to 233.

North Ward Estes.  The North Ward Estes field is located in the Ward and Winkler counties in Texas, and we continue to have significant development and related infrastructure activity in this field since we acquired it in 2005.  Our activity at North Ward Estes to date has resulted in substantial reserve additions and production increases, and our expansion of the CO2 flood in this area continues to generate positive results.

North Ward Estes has been responding positively to the water and CO2 floods that we initiated in May 2007.  In the first quarter of 2012, production from North Ward Estes averaged 8.8 MBOE/d, which was consistent with production rates in the fourth quarter of 2011.  We are currently injecting approximately 325 MMcf/d of CO2 into the field, over half of which is recycled.

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Postle.  The Postle field is located in Texas County, Oklahoma and produces from the Morrow sandstone.  Postle averaged 8.3 MBOE/d in the first quarter of 2012, which represents a 3% increase from 8.1 MBOE/d in the fourth quarter of 2011.  We are currently injecting approximately 120 MMcf/d of CO2 into the field, over half of which is recycled.

Big Tex.  Our Big Tex prospect in Pecos, Reeves and Ward counties, Texas targets the Brushy Canyon, Bone Spring and Wolfcamp horizons.  We have increased our planned capital expenditures and drilling activity in the Big Tex prospect from a 13-well drilling program to a 17-well program.  These wells will be a mixture of  vertical Wolfcamp and Wolfbone wells, horizontal Wolfcamp wells and horizontal Bone Spring wells.

Redtail.  Our Redtail prospect in Weld County, Colorado targets the Niobrara formation.  In late 2010, we initiated a seven-well exploratory drilling program (five horizontal and two vertical monitor wells) in the Niobrara formation.  Based on the results of our exploratory drilling program and recently acquired 3-D seismic data, we increased our previous eight-well drilling program for 2012 to a 17-well program, of which two were drilled in the first quarter of 2012.  We plan to resume drilling operations at our Redtail prospect in June 2012.

Acquisition and Divestiture Highlights.  On March 22, 2012, we completed the acquisition of approximately 13,300 net undeveloped acres in the Missouri Breaks prospect in Richland County, Montana for $33.3 million.

Whiting USA Trust II.  On March 28, 2012, we completed an initial public offering of units of beneficial interest in Whiting USA Trust II (“Trust II”), selling 18,400,000 Trust II units at $20.00 per unit, providing net proceeds of $323.6 million after underwriters’ fees, offering expenses and post-close adjustments.  We used the net offering proceeds to repay a portion of the debt outstanding under our credit agreement.  The net proceeds from the sale of Trust II units to the public resulted in a deferred gain on sale of $129.5 million.  Immediately prior to the closing of the offering, we conveyed a term net profits interest in certain of our oil and gas properties to Trust II in exchange for 18,400,000 trust 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.  The conveyance of the net profits interest to Trust II consisted entirely of proved reserves of 10.61 MMBOE as of the January 1, 2012 effective date, representing 3% of our proved reserves as of December 31, 2011 and 5% (or 4.5 MBOE/d) of our March 2012 average daily net production.

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Results of Operations

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

	Three Months Ended March 31,
	2012			2011
Net production:
Oil (MMBbls)		6.2			4.8
Natural gas (Bcf)		6.6			7.0
Total production (MMBOE)		7.3			5.9
Net sales (in millions):
Oil (1)	$	536.0		$	390.7
Natural gas (1)		22.7			35.0
Total oil and natural gas sales	$	558.7		$	425.7
Average sales prices:
Oil (per Bbl)	$	85.80		$	81.84
Effect of oil hedges on average price (per Bbl)		(2.26	)		(1.70	)
Oil net of hedging (per Bbl)	$	83.54		$	80.14
Average NYMEX price (per Bbl)	$	102.94		$	94.25
Natural gas (per Mcf)	$	3.43		$	5.00
Effect of natural gas hedges on average price (per Mcf)		0.07			0.04
Natural gas net of hedging (per Mcf)	$	3.50		$	5.04
Average NYMEX price (per Mcf)	$	2.72		$	4.10
Cost and expenses (per BOE):
Lease operating expenses	$	12.90		$	12.04
Production taxes	$	6.07		$	5.33
Depreciation, depletion and amortization expense	$	21.25		$	18.14
General and administrative expenses	$	4.68		$	3.10

_____________________

(1)   Before consideration of hedging transactions.

Oil and Natural Gas Sales.  Our oil and natural gas sales revenue increased $133.0 million to $558.7 million in the first quarter of 2012 compared to the same period in 2011.  Sales are a function of oil and gas volumes sold and average commodity prices realized.  Our oil sales volumes increased 31% between periods, while our natural gas sales volumes decreased 6%.  The oil volume increase resulted primarily from drilling success at our Lewis & Clark field, Sanish and Parshall fields and Hidden Bench prospect.  During the first quarter of 2012, oil production from our Lewis & Clark field increased 640 MBbl, while oil production from our Sanish and Parshall fields increased 490 MBbl, and oil production from our Hidden Bench prospect increased 180 MBbl over the same period in 2011.  Gas production volumes decreased between periods primarily due to normal field production decline across many of our areas.  During the first quarter of 2012, gas production at our Flat Rock field decreased 840 MMcf and gas production at our Canyon field decreased 210 MMcf compared to the first quarter of 2011.  These gas volume decreases were partially offset by increased gas production of 370 MMcf at our Lewis and Clark field and 255 MMcf at our Sanish and Parshall fields due to new wells drilled and completed in these areas during the last twelve months.

Also contributing to the increase in oil and gas sales revenue in 2012 was an increase in the average sales price realized for oil.  Our average price for oil before the effects of hedging increased 5% between periods. Our average price for natural gas before the effects of hedging, on the other hand, decreased 31% which was mainly due to lower average NYMEX prices during 2012.

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Gain (Loss) on Hedging Activities.  Our gain on hedging activities decreased $1.9 million in 2012 as compared to the first quarter of 2011, and it consisted of the following (in thousands):

	Three Months Ended March 31,
	2012		2011
Gains reclassified from AOCI on de-designated hedges	$	1,127	$	3,063

Effective April 1, 2009, we elected to de-designate all of our commodity derivative contracts that had been previously designated as cash flow hedges, and we elected to discontinue all hedge accounting prospectively.  Accordingly, each period we reclassify from accumulated other comprehensive income (“AOCI”) into earnings unrealized gains (which were frozen in AOCI on the April 1, 2009 de-designation date) upon the expiration of these de-designated crude oil hedges, and we report such non-cash unrealized gains as gain on hedging activities.

See Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” for a list of our outstanding oil and natural gas derivatives as of April 1, 2012.

Lease Operating Expenses.  Our lease operating expenses (“LOE”) during the first quarter of 2012 were $94.8 million, a $23.3 million increase over the same period in 2011.  This rise in LOE in 2012 was related to a $19.0 million increase in the cost of oil field goods and services associated with net wells we added during the last twelve months, as well as a higher level of workover activity.  Workovers increased to $26.3 million in the first quarter of 2012, as compared to $22.0 million in the first quarter of 2011, primarily due to a higher number of well workovers being conducted on our two main CO2 projects and at our Sanish and Parshall fields.

Our lease operating expenses on a BOE basis also increased to $12.90 during the first quarter of 2012 from $12.04 during the first quarter of 2011.  This increase on a BOE basis was mainly due to higher costs of oil field goods and services and the higher amount of workover activity in 2012, as discussed above. These cost increases incurred during the first quarter of 2012 were partially offset by higher overall production volumes between periods.

Production Taxes.  Our production taxes during the first quarter of 2012 were $44.6 million, a $13.0 million increase over the same period in 2011, which increase was primarily due to higher oil and natural gas sales between periods.  However, our production taxes are generally calculated as a percentage of oil and natural gas sales revenue before the effects of hedging, and this percentage on a company-wide basis remained relatively consistent between periods at 8.0% and 7.4% for the first quarter of 2012 and 2011, respectively.  In addition, we take advantage of credits and exemptions allowed in our various taxing jurisdictions.

Depreciation, Depletion and Amortization.  Our depreciation, depletion and amortization (“DD&A”) expense increased $48.4 million in 2012 as compared to the first quarter of 2011.  The components of our DD&A expense were as follows (in thousands):

	Three Months Ended March 31,
	2012		2011
Depletion	$	153,419	$	105,211
Depreciation		794		571
Accretion of asset retirement obligations		1,907		1,946
Total	$	156,120	$	107,728

DD&A increased in the first quarter of 2012 primarily due to $48.2 million in higher depletion expense between periods.  This increase was the result of $29.4 million in higher depletion due to a rise in overall production volumes during the first quarter of 2012 and $18.8 million in higher depletion due to an increase in our depletion rate between periods.  On a BOE basis, our DD&A rate of $21.25 for the first quarter of 2012 was 17% higher than the rate of $18.14 for the same period in 2011.  The higher DD&A rate was mainly due to $1,760.1 million in drilling and development expenditures during the past twelve months, which was partially offset by reserve additions during this same time period.

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Exploration and Impairment Costs.  Our exploration and impairment costs increased $5.3 million in the first quarter of 2012 as compared to the first quarter of 2011.  The components of our exploration and impairment costs were as follows (in thousands):

	Three Months Ended March 31,
	2012		2011
Exploration	$	9,744	$	14,599
Impairment		17,834		7,638
Total	$	27,578	$	22,237

Exploration costs decreased $4.9 million during the first quarter of 2012 as compared to the same period in 2011 primarily due to a decrease in geological and geophysical (“G&G”) activity and lower exploratory dry hole costs.  G&G costs, such as seismic studies, amounted to $3.0 million during the first quarter of 2012 as compared to $6.6 million during the same period in 2011.  We did not drill any exploratory dry holes during the three months ended March 31, 2012, while we drilled three exploratory dry holes in the Rocky Mountain, Permian Basin and Gulf Coast regions totaling $2.9 million during the first three months of 2011.  These decreases in exploration costs were partially offset by an increase of $1.5 million in geology related general and administrative expenses.

Impairment expense in the first quarter of 2012 and 2011 primarily related to the amortization of leasehold costs associated with individually insignificant unproved properties.  Undeveloped leasehold costs of $12.8 million were amortized to impairment on a group basis for the first quarter of 2012 as compared to $7.6 million in the first quarter of 2011.  In addition, acreage costs of $5.0 million were written-off to impairment expense in the first quarter of 2012 for leases that had reached their expiration dates but where no wells had been drilled on such acreage.

General and Administrative Expenses.  We report general and administrative expenses net of third party reimbursements and internal allocations.  The components of our general and administrative expenses were as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
General and administrative expenses	$	54,309		$	33,988
Reimbursements and allocations		(19,941	)		(15,575	)
General and administrative expense, net	$	34,368		$	18,413

General and administrative expense before reimbursements and allocations increased $20.3 million to $54.3 million during the first quarter of 2012 as compared to the same period in 2011 primarily due to an increase in accrued Production Participation Plan (the “Plan”) distributions and higher employee compensation.  Accrued distributions under the Plan increased general and administrative expenses by $10.9 million when comparing the first quarter of 2012 to the same period in 2011.  Of this increase in general and administrative expenses related to Plan distributions, $8.6 million related to the net profits interest divestiture associated with the sale of 18,400,000 Trust II units, and $2.3 million related to a higher level of Plan net revenues (which have been reduced by lease operating expenses and production taxes pursuant to the Plan formula).  Employee compensation increased $6.5 million in the first quarter of 2012 due to personnel hired during the past twelve months, general pay increases and higher stock compensation between periods.

The increase in reimbursements and allocations for the first quarter of 2012 was primarily caused by higher salary costs and a greater number of field workers on operated properties.  Our general and administrative expenses as a percentage of oil and natural gas sales increased from 4% in the first quarter of 2011 to 6% in the first quarter of 2012.

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Interest Expense.  The components of our interest expense were as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
Senior Subordinated Notes	$	10,062		$	10,062
Credit agreement		6,801			3,193
Amortization of debt issue costs and debt discount		2,340			2,127
Other		14			18
Capitalized interest		(761	)		(942	)
Total	$	18,456		$	14,458

The increase in interest expense of $4.0 million between periods was mainly attributable to a $3.6 million increase in the amount of interest incurred on our credit agreement during the first quarter of 2012 as compared to the first quarter of 2011.  Our credit agreement interest was higher in 2012 due to a greater amount of borrowings outstanding under our credit agreement.  Our weighted average debt outstanding during the first quarter of 2012 was $1,544.5 million versus $931.2 million for the first quarter of 2011.  Our weighted average effective cash interest rate was 4.4% during the first quarter of 2012 compared to 5.7% during the first quarter of 2011.

Commodity Derivative Loss, Net.  All of our commodity derivative contracts as well as our embedded derivatives are marked-to-market each quarter with fair value gains and losses recognized immediately in earnings, as commodity derivative loss, net.  Cash flow is only impacted to the extent that settlements under these contracts result in making or receiving a payment from the counterparty.  However, only realized cash settlement gains and losses on derivative contracts that are not embedded derivatives are recorded immediately to earnings as commodity derivative loss, net.  The components of commodity derivative loss, net were as follows (in thousands):

	Three Months Ended March 31,
	2012		2011
Change in unrealized losses on derivative contracts	$	15,672	$	126,607
Realized cash settlement losses		13,731		7,831
Total	$	29,403	$	134,438

With respect to our open derivative contracts at March 31, 2012 and 2011, the futures curve of forecasted commodity prices (“forward price curve”) for crude oil generally exceeded the forward price curves that were in effect when the majority of these contracts were entered into, resulting in a net fair value liability position at the end of each respective period.  The change in unrealized losses on derivative contracts in the first quarter of 2012 resulted in a $15.7 million loss in such net liability position due to the upward shift in the forward price curve for NYMEX crude oil from January 1 to March 31, 2012.  The change in unrealized losses on derivative contracts in 2011 resulted in a $126.6 million loss due to a more significant upward shift in the same forward price curve from January 1 to March 31, 2011.

Income Tax Expense (Benefit).  Income tax expense totaled $59.0 million for the first quarter of 2012 as compared to $12.8 million of income tax for the first quarter of 2011, an increase of $46.2 million that was mainly related to $125.2 million in higher pre-tax income between periods.  Offsetting this increase in tax expense related to higher pre-tax income, however, was a decrease in our overall effective tax rate from 39.8% for the first quarter of 2011 to 37.5% for the first quarter of 2012.  This decline in our effective income tax rate was primarily attributable to the fact that current state income tax expense remained relatively constant between periods even though our pre-tax income increased substantially in the first quarter of 2012 as compared to the first quarter of 2011.  Our effective tax rates for the periods ended March 31, 2012 and 2011 differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes and permanent taxable differences.

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Liquidity and Capital Resources

Overview.  At March 31, 2012, our debt to total capitalization ratio was 28.5%, we had $9.8 million of cash on hand and $3,116.9 million of equity.  At December 31, 2011, our debt to total capitalization ratio was 31.4%, we had $15.8 million of cash on hand and $3,020.9 million of equity.  In the first quarter of 2012, we generated $353.0 million of cash provided by operating activities, an increase of $138.9 million over the same period in 2011.  Cash provided by operating activities increased primarily due to higher crude oil production volumes and higher realized sales prices for crude oil in the first quarter of 2012.  These positive factors were partially offset by lower realized sales prices for natural gas and lower natural gas production volumes in the first quarter of 2012, as well as increased lease operating expenses, production taxes, G&G costs and general and administrative expenses during the first quarter of 2012 as compared to the same period in 2011.  Cash flows from operating activities plus $323.6 million of proceeds from the sale of Trust II units were used to finance $492.8 million of drilling and development expenditures, $46.7 million of cash acquisition capital expenditures paid in the first quarter of 2012 and $140.0 million in net repayments under our credit agreement.  The following chart details our exploration, development and undeveloped acreage expenditures incurred by region during the first quarter of 2012 (in thousands):

	Drilling and Development Expenditures(1)		Undeveloped Leasehold Expenditures		Exploration Expenditures		Total Expenditures		% of Total
Rocky Mountains	$	356,779	$	42,697	$	4,160	$	403,636		76	%
Permian Basin		93,602		617		3,460		97,679		19	%
Mid-Continent		20,002		-		517		20,519		4	%
Gulf Coast		455		3,224		1,491		5,170		1	%
Michigan		863		2		116		981		-	%
Total incurred		471,701		46,540		9,744		527,985		100	%
Decrease in accrued capital expenditures		20,858		-		-		20,858
Total paid	$	492,559	$	46,540	$	9,744	$	548,843

_____________________

(1)For purposes of this schedule, exploratory dry hole costs of $0.3 million are excluded from drilling and development expenditures as reported on the statement of cash flows and instead have been included in exploration expenditures above.

We continually evaluate our capital needs and compare them to our capital resources.  Our current 2012 capital budget is $1,800.0 million, which we expect to fund substantially with net cash provided by our operating activities.  This represents a 2% decrease from the $1,840.2 million incurred on exploration, development and acreage expenditures during 2011.  However, despite this decrease in our projected level of capital spending, we are forecasting production growth over our 2011 production level of 24.8 MMBOE.  We expect to allocate $1,399.0 million of our 2012 budget to exploration and development activity, $163.0 million for undeveloped acreage and $238.0 million for facilities.  Although we have only budgeted $163.0 million for undeveloped leaseholds in 2012, we will continue to selectively pursue property acquisitions that complement our existing core property base.  We believe that should additional attractive acquisition opportunities arise or exploration and development expenditures exceed $1,800.0 million, we will be able to finance additional capital expenditures with cash on hand, cash flows from operating activities, borrowings under our credit agreement, issuances of additional debt or equity securities, agreements with industry partners or divestitures of certain oil and gas property interests.  Our level of exploration, development and acreage expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.  We believe that we have sufficient liquidity and capital resources to execute our business plans over the next 12 months and for the foreseeable future.  In addition, with our expected cash flow streams, commodity price hedging strategies, current liquidity levels, access to debt and equity markets and flexibility to modify future capital expenditure programs, we expect to be able to fund all planned capital programs and debt repayments; comply with our debt covenants; and meet other obligations that may arise from our oil and gas operations.

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Credit Agreement.  Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), our wholly-owned subsidiary, has a credit agreement with a syndicate of banks that as of March 31, 2012 had a borrowing base of $1.5 billion with $858.6 million of available borrowing capacity, which was net of $640.0 million in borrowings and $1.4 million in letters of credit outstanding.

The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of our proved reserves that have been mortgaged to the 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 ours.  As of March 31, 2012, $48.6 million was available for additional letters of credit under the agreement.

The credit agreement provides for interest only payments until April 2016, when the entire amount borrowed is due. Interest accrues at our 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, we also incur 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.

Ratio of Outstanding Borrowings to Borrowing Base	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 0.25 to 1.0	0.50%	1.50%	0.375%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0	0.75%	1.75%	0.375%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0	1.00%	2.00%	0.50%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0	1.25%	2.25%	0.50%
Greater than or equal to 0.90 to 1.0	1.50%	2.50%	0.50%

The credit agreement contains restrictive covenants that may limit our 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 our lenders.  Except for limited exceptions, which include the payment of dividends on our 6.25% convertible perpetual preferred stock, the credit agreement also restricts our ability to make any dividend payments or distributions on our common stock.  These restrictions apply to all of the net assets of Whiting Oil and Gas.  The credit agreement requires us, 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 4.25 to 1.0 for quarters ending prior to and on December 31, 2012 and 4.0 to 1.0 for quarters ending March 31, 2013 and thereafter 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.  We were in compliance with our covenants under the credit agreement as of March 31, 2012.

For further information on the interest rates and loan security related to our credit agreement, refer to the Long-Term Debt footnote in the Notes to Consolidated Financial Statements.

Senior Subordinated Notes.  In September 2010, we issued at par $350.0 million of 6.5% Senior Subordinated Notes due October 2018.  In October 2005, we issued at par $250.0 million of 7% Senior Subordinated Notes due February 2014.

The indentures governing the notes restrict us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to 1.  If we were in violation of this covenant, then we may not be able to incur additional indebtedness, including under Whiting Oil and Gas Corporation’s credit agreement.  Additionally, the indentures governing the notes contain restrictive covenants that may limit our ability to, among other things, pay cash dividends, redeem or repurchase our capital stock or our subordinated debt, make investments or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of the assets of ours and our restricted subsidiaries taken as a whole and enter into hedging contracts.  These covenants may potentially limit the discretion of our management in certain respects.  We were in compliance with these covenants as of March 31, 2012.  However, a substantial or extended decline in oil or natural gas prices may adversely affect our ability to comply with these covenants in the future.

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Contractual Obligations and Commitments

Schedule of Contractual Obligations.  The table below does not include our Production Participation Plan liability of $102.5 million (which amount comprises both the long and short-term portions of this obligation) as of March 31, 2012, since we cannot determine with accuracy the timing or amounts of future payments.  The following table summarizes our obligations and commitments as of March 31, 2012 to make future payments under certain contracts, aggregated by category of contractual obligation, for specified time periods (in thousands):

	Payments due by period
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-term debt (a)	$	1,240,000	$	-	$	250,000	$	640,000	$	350,000
Cash interest expense on debt (b)		234,917		53,850		87,283		59,659		34,125
Derivative contract liability fair value (c)		131,606		87,960		43,646		-		-
Asset retirement obligations (d)		66,788		11,800		1,871		5,342		47,775
Tax sharing liability (e)		23,241		1,526		21,715		-		-
Purchase obligations (f)		786,963		58,031		168,026		231,143		329,763
Drilling rig contracts (g)		250,543		102,913		137,937		9,693		-
Operating leases (h)		14,382		4,706		4,484		2,265		2,927
Total	$	2,748,440	$	320,786	$	714,962	$	948,102	$	764,590

_____________________

(a) Long-term debt consists of the 7% Senior Subordinated Notes due 2014, the 6.5% Senior Subordinated Notes due 2018 and the outstanding borrowings under our credit agreement due in 2016, and assumes no principal repayment until the due dates of these instruments.

(b) Cash interest expense on the 7% Senior Subordinated Notes due 2014 and the 6.5% Senior Subordinated Notes due 2018 is estimated assuming no principal repayment until the due dates of these instruments.  Cash interest expense on the credit agreement is estimated assuming no principal repayment until the 2016 instrument due date and is estimated at a fixed interest rate of 2.1%.

(c) The above derivative obligation at March 31, 2012 primarily consists of (i) a $126.7 million fair value liability for derivative contracts we have entered into on our own behalf, primarily in the form of costless collars, to hedge our exposure to crude oil price fluctuations; (ii) a $3.4 million payable to Whiting USA Trust I (“Trust I”) for derivative contracts that we have entered into but have in turn conveyed to Trust I (although these derivatives are in a fair value asset position at quarter end, 75.8% of such derivative assets are due to Trust I under the terms of the conveyance); (iii) a $0.4 million fair value liability for derivative contracts that we have entered into on behalf of Trust II which were in a liability position at March 31, 2012; and (iv) a $0.2 million payable to Trust II for derivative contracts that we have entered into but have in turn conveyed to Trust II, which were in an asset position at quarter end.  90% of such derivative assets are due to Trust II under the terms of the conveyance.  With respect to our open derivative contracts at March 31, 2012 with certain counterparties, the forward price curve for crude oil generally exceeded the price curve that was in effect when these contracts were entered into, resulting in a derivative fair value liability.  If current market prices are higher than a collar’s price ceiling when the cash settlement amount is calculated, we are required to pay the contract counterparties.  The ultimate settlement amounts under our derivative contracts are unknown, however, as they are subject to continuing market risk and commodity price volatility.  The above derivative obligation also includes a $0.8 million liability for the embedded derivatives in two drilling rig contracts, one expiring in March 2014 and one expiring in September 2014.

(d) Asset retirement obligations represent the present value of estimated amounts expected to be incurred in the future to plug and abandon oil and gas wells, remediate oil and gas properties and dismantle their related facilities.

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(e) Amounts shown represent the present value of estimated payments due to Alliant Energy based on projected future income tax benefits attributable to an increase in our tax bases.  As a result of the Tax Separation and Indemnification Agreement signed with Alliant Energy, the increased tax bases are expected to result in increased future income tax deductions and, accordingly, may reduce income taxes otherwise payable by us.  Under this agreement, we have agreed to pay Alliant Energy 90% of the future tax benefits we realize annually as a result of this step up in tax basis for the years ending on or prior to December 31, 2013.  In 2014, we will be obligated to pay Alliant Energy the present value of the remaining tax benefits assuming all such tax benefits will be realized in future years.

(f) We have four take-or-pay purchase agreements, two agreements expiring in December 2014, one agreement expiring in December 2017 and one agreement expiring in December 2029, whereby we have committed to buy certain volumes of CO2 for use in enhanced recovery projects in our Postle field in Oklahoma and our North Ward Estes field in Texas.  The purchase agreements are with three different suppliers.  Under the terms of the agreements, we are 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, we have two ship-or-pay agreements with two different parties, one expiring in June 2013 and one expiring in December 2017, whereby we have committed to transport a minimum daily volume of CO2 via certain pipelines or else pay for any deficiencies at a price stipulated in the contract.  The CO2 volumes planned for use in the enhanced recovery projects in the Postle and North Ward Estes fields currently exceed the minimum daily volumes specified in these agreements.  Therefore, we expect to avoid any payments for deficiencies.  The purchasing obligations reported above represent our minimum financial commitment pursuant to the terms of these contracts.  However, our actual expenditures under these contracts are expected to exceed the minimum commitments presented above.

(g) We currently have 14 drilling rigs under long-term contract, of which three drilling rigs expire in 2012, two in 2013, six in 2014 and three in 2015.  All of these rigs are operating in the Rocky Mountains region.  As of March 31, 2012, early termination of the remaining contracts would require termination penalties of $177.8 million, which would be in lieu of paying the remaining drilling commitments of $250.5 million.  No other drilling rigs working for us are currently under long-term contracts or contracts that cannot be terminated at the end of the well that is currently being drilled.  Due to the short-term and indeterminate nature of the time remaining on rigs drilling on a well-by-well basis, such obligations have not been included in this table.

(h) We lease 135,026 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2013, 46,300 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.

Based on current oil and natural gas prices and anticipated levels of production, we believe that the estimated net cash generated from operations, together with cash on hand and amounts available under our credit agreement, will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and exploration and development activities.

New Accounting Pronouncements

For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to the Adopted and Recently Issued Accounting Pronouncements footnote in the Notes to Consolidated Financial Statements.

Critical Accounting Policies and Estimates

Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

Effects of Inflation and Pricing

We experienced increased costs during 2011 and the first quarter of 2012 due to increased demand for oil field products and services.  The oil and gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry.  Typically, as prices for oil and natural gas increase, so do all associated costs.  Conversely, in a period of declining prices, associated cost declines are likely to lag and not adjust downward in proportion to prices.  Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions.  Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel.  While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

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Forward-Looking Statements

This report contains statements that we believe to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995.  All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements.  When used in this report, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements.  Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

These risks and uncertainties include, but are not limited to:  declines in oil or natural gas prices; our level of success in exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures, including our ability to obtain CO2; inaccuracies of our reserve estimates or our assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; risks related to our level of indebtedness and periodic redeterminations of the borrowing base under our credit agreement; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations and acquisitions; federal and state initiatives relating to the regulation of hydraulic fracturing; the potential impact of federal debt reduction initiatives and tax reform legislation being considered by the U.S. Federal government that could have a negative effect on the oil and gas industry; impacts of the global recession and tight credit markets; our ability to identify and complete acquisitions and to successfully integrate acquired businesses; unforeseen underperformance of or liabilities associated with acquired properties; our ability to successfully complete potential asset dispositions; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry in the regions in which we operate; risks arising out of our hedging transactions; and other risks described under the caption “Risk Factors” in our Annual Report on Form 10-K for the period ended December 31, 2011.  We assume no obligation, and disclaim any duty, to update the forward-looking statements in this Quarterly Report on Form 10-Q.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

Our quantitative and qualitative disclosures about market risk for changes in commodity prices and interest rates are included in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2011 and have not materially changed since that report was filed.

Commodity Derivative Contracts—Our outstanding hedges as of April 1, 2012 are summarized below:

Whiting Petroleum Corporation

Commodity	Period	Monthly Volume (Bbl)	Weighted Average NYMEX Floor/Ceiling
Crude Oil	04/2012 to 06/2012	975,000	$66.56/$108.26
Crude Oil	07/2012 to 09/2012	975,000	$66.56/$108.26
Crude Oil	10/2012 to 12/2012	975,000	$66.56/$108.26
Crude Oil	01/2013 to 03/2013	290,000	$47.67/$90.21
Crude Oil	04/2013 to 06/2013	290,000	$47.67/$90.21
Crude Oil	07/2013 to 09/2013	290,000	$47.67/$90.21
Crude Oil	10/2013	290,000	$47.67/$90.21
Crude Oil	11/2013	190,000	$47.22/$85.06

In connection with our conveyance on April 30, 2008 of a term net profits interest to Whiting USA Trust I (“Trust I”), the rights to any future hedge payments we make or receive on certain of our derivative contracts, representing 322 MBbls of crude oil and 1,173 MMcf of natural gas in 2012, have been conveyed to Trust I, and therefore such payments will be included in Trust I’s calculation of net proceeds.  Under the terms of the aforementioned conveyance, we retain 10% of the net proceeds from the underlying properties.  Our retention of 10% of these net proceeds combined with our ownership of 2,186,389 Trust I units, results in third-party public holders of Trust I units receiving 75.8%, while we retain 24.2%, of future economic results of such hedges.  No additional hedges are allowed to be placed on Trust I assets.

The table below summarizes all of the outstanding costless collars that we entered into and then in turn conveyed, as described in the preceding paragraph, to Trust I (of which we retain 24.2% of the future economic results and third-party public holders of Trust I units receive 75.8% of the future economic results):

Conveyed to Whiting USA Trust I

Commodity	Period	Monthly Volume (Bbl)/(Mcf)	Weighted Average NYMEX Floor/Ceiling
Crude Oil	04/2012 to 06/2012	36,572	$74.00/$141.73
Crude Oil	07/2012 to 09/2012	35,742	$74.00/$141.70
Crude Oil	10/2012 to 12/2012	35,028	$74.00/$142.21
Natural Gas	04/2012 to 06/2012	134,203	$6.00/$13.60
Natural Gas	07/2012 to 09/2012	130,173	$6.00/$14.45
Natural Gas	10/2012 to 12/2012	126,613	$7.00/$13.40

In connection with our conveyance on March 28, 2012 of a term net profits interest to Whiting USA Trust II (“Trust II”), the rights to any future hedge payments we make or receive on certain of our derivative contracts, representing 1,459 MBbls of crude oil from 2012 through 2014, 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, we retain 10% of the net proceeds from the underlying properties.  This results in third-party public holders of Trust II units receiving 90%, while we retain 10%, of the future economic results of such hedges.  No additional hedges are allowed to be placed on Trust II assets.

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The table below summarizes all of the outstanding costless collars that we entered into and then in turn conveyed, as described in the preceding paragraph, to Trust II (of which we retain 10% of the future economic results and third-party public holders of Trust II units receive 90% of the future economic results):

Conveyed to Whiting USA Trust II

Commodity	Period	Monthly Volume (Bbl)	Weighted Average NYMEX Floor/Ceiling
Crude Oil	04/2012 to 06/2012	48,400	$80.00/$122.50
Crude Oil	07/2012 to 09/2012	47,900	$80.00/$122.50
Crude Oil	10/2012 to 12/2012	46,800	$80.00/$122.50
Crude Oil	01/2013 to 03/2013	45,600	$80.00/$122.50
Crude Oil	04/2013 to 06/2013	45,500	$80.00/$122.50
Crude Oil	07/2013 to 09/2013	44,500	$80.00/$122.50
Crude Oil	10/2013 to 12/2013	43,400	$80.00/$122.50
Crude Oil	01/2014 to 03/2014	42,500	$80.00/$122.50
Crude Oil	04/2014 to 06/2014	41,500	$80.00/$122.50
Crude Oil	07/2014 to 09/2014	40,600	$80.00/$122.50
Crude Oil	10/2014 to 12/2014	39,700	$80.00/$122.50

The collared hedges shown above have the effect of providing a protective floor while allowing us to share in upward pricing movements.  Consequently, while these hedges are designed to decrease our exposure to price decreases, they also have the effect of limiting the benefit of price increases above the ceiling.  For the crude oil hedges outstanding as of March 31, 2012, a hypothetical upward or downward shift of $10.00 per Bbl in the NYMEX forward curve as of March 31, 2012 would cause a decrease or increase, respectively, of $78.2 million in our commodity derivative loss.  For the natural gas hedges outstanding as of March 31, 2012, a hypothetical $1.00 per Mcf upward or downward shift in the NYMEX forward curve as of March 31, 2012 would cause a decrease or increase, respectively, in our commodity derivative loss of $0.2 million.

We have various fixed price gas sales contracts with end users for a portion of the natural gas we produce in Colorado, Michigan and Utah.  Our estimated future production volumes to be sold under these fixed price contracts as of April 1, 2012 are summarized below:

Commodity	Period	Monthly Volume (MMBtu)	Weighted Average Price Per MMBtu
Natural Gas	04/2012 to 06/2012	461,296	$5.41
Natural Gas	07/2012 to 09/2012	465,630	$5.41
Natural Gas	10/2012 to 12/2012	398,667	$5.46
Natural Gas	01/2013 to 03/2013	360,000	$5.47
Natural Gas	04/2013 to 06/2013	364,000	$5.47
Natural Gas	07/2013 to 09/2013	368,000	$5.47
Natural Gas	10/2013 to 12/2013	368,000	$5.47
Natural Gas	01/2014 to 03/2014	330,000	$5.49
Natural Gas	04/2014 to 06/2014	333,667	$5.49
Natural Gas	07/2014 to 09/2014	337,333	$5.49
Natural Gas	10/2014 to 12/2014	337,333	$5.49

Embedded Commodity Derivative Contracts—The price we pay for oil field products and services significantly impacts our profitability, reserve estimates, access to capital and future growth rate.  Typically, as prices for oil and natural gas increase, so do all associated costs.  We have entered into certain contracts for oil field goods and services with price adjustment clauses that are linked to changes in NYMEX crude oil prices to reduce our exposure to paying higher than the market rates for these goods and services in a climate of declining oil prices.  We have determined that the portions of these contracts linked to NYMEX oil prices are not clearly and closely related to the host contracts, and we have therefore bifurcated these embedded pricing features from their host contracts and reflected them at fair value in the consolidated financial statements.  These embedded commodity derivative contracts have not been designated as hedges, and therefore all changes in fair value since inception have been recorded immediately to earnings.

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As of March 31, 2012, we had two contracts with drilling rig companies, whereby the rig day rates increased or decreased along with changes in the price of NYMEX crude oil.  These drilling rig contracts have termination dates of March 2014 and September 2014.  For these embedded commodity derivative contracts, a hypothetical upward or downward shift of $10.00 per Bbl in the NYMEX forward curve as of March 31, 2012 would cause a decrease or increase, respectively, of $1.5 million in our commodity derivative loss.

In May 2011, we entered into a long-term contract to purchase CO2 from 2015 through 2029 for use in our enhanced oil recovery project at our North Ward Estes field in Texas.  The price per Mcf of CO2 purchased under this agreement increases or decreases as the average price of NYMEX crude oil likewise increases or decreases.  For this embedded commodity derivative contract, a hypothetical upward or downward shift of $10.00 per Bbl in the NYMEX forward curve as of March 31, 2012 would cause a decrease or increase, respectively, of $14.1 million in our commodity derivative loss.

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures.  In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated, with the participation of our Chairman and Chief Executive Officer and our Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of March 31, 2012.  Based upon their evaluation of these disclosures controls and procedures, the Chairman and Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of March 31, 2012 to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting.  There was no change in our internal control over financial reporting that occurred during the quarter ended March 31, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Whiting is subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business.  It is management’s opinion that all claims and litigation we are involved in are not likely to have a material adverse effect on our consolidated financial position, cash flows or results of operations.

Item 1A. Risk Factors

Risk factors relating to us are contained in Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2011.  No material change to such risk factors has occurred during the three months ended March 31, 2012.

Item 5. Other Information

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, which provides guidance on the presentation of comprehensive income in financial statements.  Entities are required to present total comprehensive income either in a single, continuous statement of comprehensive income or in two separate, but consecutive, statements.  We adopted this standard effective January 1, 2012 and will present net income and other comprehensive income in two separate statements in our interim and annual financial statements.  The table below reflects the retrospective application of this guidance for each of the three years ended December 31, 2011, 2010 and 2009.  The retrospective application did not have an impact on our consolidated financial statements other than requiring us to present our statements of comprehensive income separately from our statements of equity, as these statements were previously presented on a combined basis.

Whiting Petroleum Corporation

Consolidated Statements of Comprehensive Income (Loss)

(In thousands)

	Year Ended December 31,
	2011			2010			2009
Net income (loss)	$	491,628		$	336,653		$	(106,882	)
Other comprehensive income (loss), net of tax:
Change in derivative fair values,net of taxes of $7,799		-			-			13,348
Realized gain on settled derivatives, net of taxes of $4,933		-			-			(8,517	)
Ineffectiveness loss on hedging activities, net of taxes of $8,355		-			-			14,300
OCI amortization on de-designated hedges(1)		(5,528	)		(14,645	)		(15,989	)
Total other comprehensive income (loss), net of tax		(5,528	)		(14,645	)		3,142
Comprehensive income (loss)		486,100			322,008			(103,740	)
Comprehensive loss attributable to noncontrolling interest		59			-			-
Comprehensive income (loss) attributable to Whiting	$	486,159		$	322,008		$	(103,740	)
(1) Presented net of income tax expense of $3,230, $8,553 and $9,337 for the years ended December 31, 2011 and 2010 and 2009, respectively.

40

Item 6. Exhibits

The exhibits listed in the accompanying index to exhibits are filed as part of this Quarterly Report on Form 10-Q.

41

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on this 27th day of April, 2012.

	WHITING PETROLEUM CORPORATION
By	/s/ James J. Volker
	James J. Volker
	Chairman and Chief Executive Officer
By	/s/ Michael J. Stevens
	Michael J. Stevens
	Vice President and Chief Financial Officer
By	/s/ Brent P. Jensen
	Brent P. Jensen
	Controller and Treasurer

42

EXHIBIT INDEX

Exhibit Number	Exhibit Description
(31.1)	Certification by the Chairman and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
(31.2)	Certification by the Vice President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
(32.1)	Certification of the Chairman and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
(32.2)	Certification of the Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
(101)	The following materials from Whiting Petroleum Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 are furnished herewith, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011, (ii) the Consolidated Statements of Income for the Three Months Ended March 31, 2012 and 2011, (iii) the Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2012 and 2011, (iv) the Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011, (v) the Consolidated Statements of Equity for the Three Months Ended March 31, 2012 and 2011 and (vi) Notes to Consolidated Financial Statements.

43

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, James J. Volker, certify that:

1.           I have reviewed this Quarterly Report on Form 10-Q of Whiting Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 27, 2012

/s/ James J. Volker

James J. Volker

Chairman and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Michael J. Stevens, certify that:

1.           I have reviewed this Quarterly Report on Form 10-Q of Whiting Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 27, 2012

/s/ Michael J. Stevens

Michael J. Stevens

Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Written Statement of the Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350

Solely for the purposes of complying with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, I, the undersigned Chairman and Chief Executive Officer of Whiting Petroleum Corporation, a Delaware corporation (the “Company”), hereby certify, based on my knowledge, that the Quarterly Report on Form 10-Q of the Company for the quarter ended March 31, 2012 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ James J. Volker

James J. Volker

Chairman and Chief Executive Officer

Date: April 27, 2012

EX-32.2

Exhibit 32.2

Written Statement of the Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350

Solely for the purposes of complying with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, I, the undersigned Vice President and Chief Financial Officer of Whiting Petroleum Corporation, a Delaware corporation (the “Company”), hereby certify, based on my knowledge, that the Quarterly Report on Form 10-Q of the Company for the quarter ended March 31, 2012 (the “Report”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Michael J. Stevens

Michael J. Stevens

Vice President and Chief Financial Officer

Date: April 27, 2012

XML

Derivative Financial Instruments (Details 4) (Third Party Public Holders of Trust II Units [Member], Crude oil [Member])	Mar. 31, 2012 bbl
Derivative [Line Items]
Number of Price Risk Derivatives Held	1,313,280
Apr - Dec 2012 [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	386,370
Apr - Dec 2012 [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	80.00
Apr - Dec 2012 [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	122.50
Jan - Dec 2013 [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	483,300
Jan - Dec 2013 [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	80.00
Jan - Dec 2013 [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	122.50
Jan - Dec 2014 [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	443,610
Jan - Dec 2014 [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	80.00
Jan - Dec 2014 [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	122.50

XML

Income Taxes (Details)	3 Months Ended
	Mar. 31, 2012
Income Taxes Additional (Textual) [Abstract]
U.S. statutory income tax rate	35.00%

XML

Shareholders Equity and Noncontrolling Interest (Details) (Restricted Stock [Member])	3 Months Ended
	Mar. 31, 2012 SimulationPath	Mar. 31, 2011 SimulationPath
Restricted Stock [Member]
Assumption for valuing market based restricted shares
Number of simulations	65,000	65,000
Expected volatility	51.90%	75.80%
Risk-free interest rate	0.35%	1.00%

XML

Earnings Per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Numerator:
NET INCOME	$ 98,470	$ 19,414
Preferred stock dividends	269	270
Net income available to common shareholders, basic	98,201	19,144
Denominator:
Weighted average shares outstanding, basic	117,517	117,243
Numerator:
Net income available to common shareholders, basic	98,201	19,144
Preferred stock dividends	269
Adjusted net income available to common shareholders, diluted	$ 98,470	$ 19,144
Denominator:
Weighted average shares outstanding, basic	117,517	117,243
Restricted stock and stock options	585	591
Convertible perpetual preferred stock	794
Weighted average shares outstanding, diluted	118,896	117,834
Earnings (loss) per common share, basic	$ 0.84	$ 0.16
Earnings (loss) per common share, diluted	$ 0.83	$ 0.16

XML

Deferred Compensation (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Changes in Estimated Long-Term Liability
Long-term Production Participation Plan Liability at January 1	$ 80,659
Change in Liability for accretion, vesting, change in estimates and new Plan year activity	21,815
Cash payments accrued as compensation expense and reflected as a current payable	(20,880)
Long-term Production Participation Plan Liability at March 31	$ 81,594

XML

Long-Term Debt (Details Textual) (USD $)	3 Months Ended			12 Months Ended			1 Months Ended		1 Months Ended		3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Whiting Oil and Gas and Whiting Programs, Inc [Member]	Mar. 31, 2012 Credit agreement [Member]	Sep. 30, 2010 6.5% Senior Subordinated Notes due 2018 [Member]	Mar. 31, 2012 6.5% Senior Subordinated Notes due 2018 [Member]	Oct. 31, 2005 7% Senior Subordinated Notes due 2014 [Member]	Mar. 31, 2012 7% Senior Subordinated Notes due 2014 [Member]	Mar. 31, 2012 Convertible perpetual preferred stock [Member]
Debt Instrument [Line Items]
Interest rate on debt instrument								6.50%		7.00%
Borrowing outstanding						$ 640,000,000
Letters of credit outstanding						1,400,000
Amount of revolving credit agreement available for additional letters of credit under the agreement						48,600,000
Interest rate on convertible perpetual preferred stock			6.25%	6.25%							6.25%
Senior Subordinated Notes issued at par							350,000,000		250,000,000
Estimated fair value of Senior Subordinated Notes								372,300,000		266,900,000
Percentage of ownership in subsidiary			15.80%		100.00%
Long Term Debt (Textual) [Abstract]
Extension of date for credit agreement			Apr. 01, 2016
Borrowing base of credit facility			1,500,000,000
Borrowing capacity of credit facility			858,600,000
Revolving credit facility amount used to issue letter of credit			not to exceed $50.0 million
Interest accrued at the Company's option			(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
Interest for base rate loan plus federal fund rate			0.50%
Interest for base rate loan plus adjusted Libor rate			1.00%
Weighted average interest rate on the outstanding principal balance borrowed under the credit agreement			2.10%
Condition for credit agreement			(i) to not exceed a total debt to the last four quarters’ EBITDAX ratio (as defined in the credit agreement) of 4.25 to 1.0 for quarters ending prior to and on December 31, 2012 and 4.0 to 1.0 for quarters ending March 31, 2013 and thereafter 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.
EBITDAX ratio (percentage)	4.0	4.25
Consolidated current assets to consolidated current liabilities ratio (percentage)			1.0
Restricted net assets			2,961,000,000
Retained earnings free from restrictions			$ 17,800,000

XML

Derivative Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2012

Derivative [Line Items]

Location and fair value of derivative instruments

		Fair Value
Not Designated as ASC 815 Hedges	Balance Sheet Classification	March 31, 2012		December 31, 2011
Derivative assets:
Commodity contracts	Prepaid expenses and other	$	4,850	$	5,719
Embedded commodity contracts	Prepaid expenses and other		—		240
Commodity contracts	Other long-term assets		242		—
Embedded commodity contracts	Other long-term assets		8,866		13,347
Total derivative assets		$	13,958	$	19,306
Derivative liabilities:
Commodity contracts	Current derivative liabilities	$	87,517	$	73,647
Embedded commodity contracts	Current derivative liabilities		443		—
Commodity contracts	Non-current derivative liabilities		43,243		47,763
Embedded commodity contracts	Non-current derivative liabilities		403		—
Total derivative liabilities		$	131,606	$	121,410

(Gain) Loss Recognized in Income

		Gain Reclassified from OCI into Income (Effective Portion)
ASC 815 Cash Flow		Three Months Ended March 31,
Hedging Relationships	Income Statement Classification	2012		2011
Commodity contracts	Gain on hedging activities	$	1,127	$	3,063

		Loss Recognized in Income
Not Designated as		Three Months Ended March 31,
ASC 815 Hedges	Income Statement Classification	2012		2011
Commodity contracts	Commodity derivative loss, net	$	23,837	$	131,357
Embedded commodity contracts	Commodity derivative loss, net		5,566		3,081
Total		$	29,403	$	134,438

Whiting Petroleum Corporation [Member]

Derivative [Line Items]

Derivative instruments

	Whiting Petroleum Corporation
	Contracted Volumes				Weighted Average NYMEX Price Collar Ranges
Period	Crude Oil (Bbl)		Natural Gas (Mcf)		Crude Oil (per Bbl)	Natural Gas (per Mcf)
Apr — Dec 2012		8,895,860		283,858	$ 66.71 - $108.62	$6.32 - $13.82
Jan — Dec 2013		3,143,700		—	$ 48.20 - $ 90.45	n/a
Jan — Dec 2014		49,290		—	$ 80.00 - $122.50	n/a
Total		12,088,850		283,858

	Whiting Petroleum Corporation
	Contracted Volumes				Weighted Average NYMEX Price Collar Ranges
Period	Crude Oil (Bbl)		Natural Gas (Mcf)		Crude Oil (per Bbl)		Natural Gas (per Mcf)
Apr — Dec 2012		77,930		283,858	$	74.00 - $141.87	$	6.32 - $13.82

	Third-party Public Holders of Trust I Units
	Contracted Volumes				Weighted Average NYMEX Price Collar Ranges
Period	Crude Oil (Bbl)		Natural Gas (Mcf)		Crude Oil (per Bbl)	Natural Gas (per Mcf)
Apr — Dec 2012		244,096		889,109	$74.00 - $141.87	$6.32 - $13.82

	Whiting Petroleum Corporation
	Contracted Crude Oil Volumes (Bbl)		Weighted Average NYMEX Price Collar Ranges for Crude Oil (per Bbl)
Apr — Dec 2012		42,930	$80.00 - $122.50
Jan — Dec 2013		53,700	$80.00 - $122.50
Jan — Dec 2014		49,290	$80.00 - $122.50
		145,920

	Third-party Public Holders of Trust II Units
	Contracted Crude Oil Volumes (Bbl)		Weighted Average NYMEX Price Collar Ranges for Crude Oil (per Bbl)
Apr — Dec 2012		386,370	$80.00 - $122.50
Jan — Dec 2013		483,300	$80.00 - $122.50
Jan — Dec 2014		443,610	$80.00 - $122.50
		1,313,280

XML

Shareholders Equity and Noncontrolling Interest (Details 2) (Stock Options [Member])	3 Months Ended
	Mar. 31, 2012 Y	Mar. 31, 2011 Y
Stock Options [Member]
Assumption for valuing market based restricted shares
Risk-free interest rate	1.19%	2.47%
Expected volatility	61.40%	59.30%
Expected term	6.0	6.0
Dividend yield

XML

Derivative Financial Instruments (Details Textual) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2012 Contract	Dec. 31, 2011
Derivative Financial Instruments Textual Abstract
Net profits interest to the Trust 1 and related sale	11,677,500
Ownership Trust1 units	2,186,389
Share of third-party public holders of Trust1 units	75.80%
Share of whitening petroleum	24.20%
Net profits interest to the Trust II and related sale	18,400,000
Number of Contracts with drilling rig companies	2
Termination date range for drilling rig contracts	From March 2014 to September 2014
Increase decrease in price of crude oil, price adjustment formula	$ 10
The aggregate estimated fair value of the embedded derivatives in drilling rig contracts (Asset)	800,000
The estimated fair value of the embedded derivative in this CO2 purchase contract (Asset)	$ 8,900,000
Termination date range for CO2 contract		2015 through 2029
Whiting Petroleum Corporation [Member]
Derivative [Line Items]
Retention of net proceeds from the underlying properties	10.00%
Third Party Public Holders of Trust 1 Units [Member]
Derivative [Line Items]
Retention of net proceeds from the underlying properties	90.00%

XML

Derivative Financial Instruments (Details 2) (Third Party Public Holders of Trust 1 Units [Member], Apr - Dec 2012 [Member])	Mar. 31, 2012 bbl
Crude Oil [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	244,096
Derivative, Floor Price	74.00
Derivative, Cap Price	141.87
Natural gas [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	889,109
Derivative, Floor Price	6.32
Derivative, Cap Price	13.82

XML

Shareholders Equity and Noncontrolling Interest (Details 4) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Schedule of Noncontrolling interest
Balance at January 1	$ 8,274
Contributions from noncontrolling interest		8,333
Net income (loss)	(24)
Balance at March 31	$ 8,250	$ 8,333

XML

Deferred Compensation (Details Textual) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Additional Deferred Compensation (Textual) [Abstract]
Percentage of plan interests paid to employees at year end	100.00%
Percentage of employees vesting ratably per year	20.00%
Plan Period	P5Y
Fully vested age of employees	62
Average historical prices of crude oil	82.50
Average Historical Prices of Natural Gas	4.01
Fully Vested Lump sum Cash Payment to Employees in Case of Termination of Plan or Change of Control	$ 167.6
Amount attributable to proved undeveloped oil and gas properties	15.0
Short-term portion of Plan Liability which has been accrued as Current Payable	20.9
Minimum [Member]
Deferred Compensation (Textual) [Abstract]
Overriding royalty interest in interest allocation prior to 1995	2.00%
Portion of Oil and Gas Sales Less Lease Operating Expenses and Production Taxes Allocated to Interest since 1995	2.00%
Maximum [Member]
Deferred Compensation (Textual) [Abstract]
Overriding royalty interest in interest allocation prior to 1995	3.00%
Portion of Oil and Gas Sales Less Lease Operating Expenses and Production Taxes Allocated to Interest since 1995	5.00%
General and administrative expense [Member]
Deferred Compensation (Textual) [Abstract]
Accrued compensation expense allocation	18.9	8.0
Exploration expense [Member]
Deferred Compensation (Textual) [Abstract]
Accrued compensation expense allocation	$ 2.0	$ 0.9

XML

Consolidated Statements of Equity (Unaudited) (USD $) In Thousands	Total	Preferred Stock	Common Stock	Additional Paid-in Capital	Accumulated Other Comprehensive Income (Loss)	Retained Earnings	Total Whiting Shareholders' Equity	Noncontrolling Interests
Beginning balance at Dec. 31, 2010	$ 2,531,315		$ 59	$ 1,549,822	$ 5,768	$ 975,666	$ 2,531,315
Conversion of preferred stock to common, Shares at Dec. 31, 2010		(1)	1
Beginning balance, shares at Dec. 31, 2010		173	117,968
Net income	19,414					19,414	19,414
OCI amortization on de-designated hedges, net of taxes	(1,934)				(1,934)		(1,934)
Conversion of preferred stock to common, Amount
Two-for-one stock split			59	(59)
Contributions from noncontrolling interest	8,333							8,333
Restricted stock issued, shares			293
Restricted stock forfeited			(3)
Restricted stock used for tax withholdings	(8,944)			(8,944)			(8,944)
Restricted stock used for tax withholdings, shares			(147)
Stock-based compensation	3,164			3,164			3,164
Preferred dividends paid	(270)					(270)	(270)
Ending balance at Mar. 31, 2011	2,551,078		118	1,543,983	3,834	994,810	2,542,745	8,333
Ending balance, shares at Mar. 31, 2011		172	118,112
Beginning balance at Dec. 31, 2011	3,029,131		118	1,554,223	240	1,466,276	3,020,857	8,274
Beginning balance, shares at Dec. 31, 2011		172	118,105
Net income	98,446					98,470	98,470	(24)
OCI amortization on de-designated hedges, net of taxes	(712)				(712)		(712)
Restricted stock issued, shares			569
Restricted stock issued, amount			1	(1)
Restricted stock forfeited			(3)
Restricted stock used for tax withholdings	(5,657)			(5,657)			(5,657)
Restricted stock used for tax withholdings, shares			(106)
Stock-based compensation	4,243			4,243			4,243
Preferred dividends paid	(269)					(269)	(269)
Ending balance at Mar. 31, 2012	$ 3,125,182		$ 119	$ 1,552,808	$ (472)	$ 1,564,477	$ 3,116,932	$ 8,250
Ending balance, shares at Mar. 31, 2012		172	118,565

XML

Fair Value Measurments (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Financial Assets
Total financial assets	$ 8,866
Recurring Basis [Member]
Financial Assets
Total financial assets	13,958	19,306
Financial Liabilities
Total financial liabilities	131,606	121,410
Recurring Basis [Member] | Commodity contracts [Member]
Financial Assets
Financial assets - current	4,850	5,719
Financial assets - non-current	242
Financial Liabilities
Financial liabilities - current	87,517	73,647
Financial liabilities - non-current	43,243	47,763
Recurring Basis [Member] | Embedded commodity contracts [Member]
Financial Assets
Financial assets - current	8,866	240
Financial assets - non-current		13,347
Financial Liabilities
Financial liabilities - current	443
Financial liabilities - non-current	403
Recurring Basis [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Assets
Total financial assets
Financial Liabilities
Total financial liabilities
Recurring Basis [Member] | Fair Value, Inputs, Level 1 [Member] | Commodity contracts [Member]
Financial Assets
Financial assets - current
Financial assets - non-current
Financial Liabilities
Financial liabilities - current
Financial liabilities - non-current
Recurring Basis [Member] | Fair Value, Inputs, Level 1 [Member] | Embedded commodity contracts [Member]
Financial Assets
Financial assets - current
Financial assets - non-current
Financial Liabilities
Financial liabilities - current
Financial liabilities - non-current
Recurring Basis [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Assets
Total financial assets	5,092	6,326
Financial Liabilities
Total financial liabilities	131,606	121,410
Recurring Basis [Member] | Fair Value, Inputs, Level 2 [Member] | Commodity contracts [Member]
Financial Assets
Financial assets - current	4,850	5,719
Financial assets - non-current	242
Financial Liabilities
Financial liabilities - current	87,517	73,647
Financial liabilities - non-current	43,243	47,763
Recurring Basis [Member] | Fair Value, Inputs, Level 2 [Member] | Embedded commodity contracts [Member]
Financial Assets
Financial assets - current		240
Financial assets - non-current		367
Financial Liabilities
Financial liabilities - current	443
Financial liabilities - non-current	403
Recurring Basis [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Assets
Total financial assets	8,866	12,980
Recurring Basis [Member] | Fair Value, Inputs, Level 3 [Member] | Embedded commodity contracts [Member]
Financial Assets
Financial assets - current	8,866
Financial assets - non-current		$ 12,980

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

Reconciliations between basic and diluted earnings per share

	Three Months Ended March 31,
	2012			2011
Basic Earnings Per Share
Numerator:
Net income available to shareholders	$	98,470		$	19,414
Preferred stock dividends		(269	)		(270	)
Net income available to common shareholders, basic	$	98,201		$	19,144
Denominator:
Weighted average shares outstanding, basic		117,517			117,243
Diluted Earnings Per Share
Numerator:
Net income available to common shareholders, basic	$	98,201		$	19,144
Preferred stock dividends		269			—
Adjusted net income available to common shareholders, diluted	$	98,470		$	19,144
Denominator:
Weighted average shares outstanding, basic		117,517			117,243
Restricted stock and stock options		585			591
Convertible perpetual preferred stock		794			—
Weighted average shares outstanding, diluted		118,896			117,834
Earnings per common share, basic	$	0.84		$	0.16
Earnings per common share, diluted	$	0.83		$	0.16

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Shareholders' Equity and Noncontrolling Interest [Tables]

3 Months Ended

Mar. 31, 2012

Shareholders' Equity and Noncontrolling Interest [Abstract]

Assumption for valuing market based restricted shares

	2012			2011
Number of simulations		65,000			65,000
Expected volatility		51.9	%		75.8	%
Risk-free rate		0.35	%		1.00	%

Summary of nonvested restricted stock

	Number of Shares			Weighted Average Grant Date Fair Value
Restricted stock awards nonvested, January 1, 2012		724,395		$	29.88
Granted		568,661			34.20
Vested		(342,556	)		16.92
Forfeited		(2,927	)		51.59
Restricted stock awards nonvested, March 31, 2012		947,573		$	37.09

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 Options		Weighted Average Exercise Price per Share		Aggregate Intrinsic Value		Weighted Average Remaining Contractual Term (in Years)
Options outstanding at January 1, 2012		377,336	$	26.09
Granted		45,358		51.22
Exercised		—		—	$	—
Forfeited or expired		—		—
Options outstanding at March 31, 2012		422,694	$	28.79	$	11,265.2		7.7
Options vested and expected to vest at March 31, 2012		422,694	$	28.79	$	11,265.2		7.7
Options exercisable at March 31, 2012		305,022	$	19.56	$	10,757.0		7.2

Schedule of Noncontrolling interest

	Three Months Ended March 31,
	2012			2011
Balance at January 1	$	8,274		$	—
Contributions from noncontrolling interest		—			8,333
Net income (loss)		(24	)		—
Balance at March 31	$	8,250		$	8,333

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Earnings Per Share (Details Textual)	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Earnings Per Share, Basic and Diluted, (Textual) [Abstract]
Anti-dilutive restricted stock and stock options excluded from diluted earnings per share calculation		794,330
Shares excluded from Earnings Per Share calculation, Stock Options	7,006

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Fair Value Measurments (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy
Fair value asset asset, beginning of period	$ 12,980
Unrealized gains (losses) on embedded commodity derivative contracts included in earnings	(4,114)
Transfers into (out of) Level 3
Fair value asset end of period	$ 8,866

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Basis of Presentation (Details)	Mar. 31, 2012
Basis Of Presentation (Textual) [Abstract]
Percentage of ownership in subsidiary	15.80%

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Acquisitions and Divestitures (Details) (USD $)	3 Months Ended								3 Months Ended
	Mar. 31, 2012 MMBoe bbl	Mar. 31, 2011	Mar. 28, 2012	Sep. 29, 2011	Feb. 15, 2011	Mar. 22, 2012 Missouri Breaks Prospect [Member] acre	Jul. 28, 2011 Missouri Breaks Prospect [Member] acre Well	Feb. 15, 2011 North Dakota [Member] acre	Mar. 31, 2012 Whiting Proved Reserves [Member]	Mar. 31, 2012 Sustainable Water Resources, LLC [Member]	Mar. 18, 2011 Sustainable Water Resources, LLC [Member]
Business Acquisition [Line Items]
Amount contributed in ownership											$ 25,000,000
Noncontrolling interest, ownership percentage by parent	15.80%										75.00%
Noncontrolling interest, ownership percentage by noncontrolling owners											25.00%
Total fair value											8,300,000
Cash contributions in fair value											2,500,000
Tangible and intangible assets contributed in fair value		5,833,000								5,800,000
Additional Acquisitions and Divestitures (Textual) [Abstract]
Net acquisition area in acres						13,300	23,400	6,000
Purchase price for acquisition				64,800,000	40,000,000	33,300,000	46,900,000
Acquisition costs and sale proceeds of acquisitions and divestitures	323,600,000
Number of well acquired							1
Whiting USA Trust II estimated proved reserves	10.61
Percentage of Company's total proved reserves	90.00%
Percentage of Company's net production	5.00%								3.00%
Average daily net production	4.5
Acquisitions and Divestitures (Textual) [Abstract]
Pre tax gain on Divestiture				12,300,000
Number of shares sold	18,400,000
Price per unit of shares			$ 20.00
Deferred gain on sale			$ 129,500,000
Percentage of net proceeds from sale received	90.00%
Terminating period of net profit interest	Dec. 31, 2021
Barrel of oil produced from underlying properties and sold	11.79
Proved producing reserves received	10.61

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Consolidated Statements of Cash Flows (Unaudited) (Parenthetical)	3 Months Ended
	Mar. 31, 2012
Consolidated Statements of Cash Flows [Abstract]
Proceeds from sale of units	18,400,000

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Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified			3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Less than 0.25 to 1.0 [Member]	Mar. 31, 2012 Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member]	Mar. 31, 2012 Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member]	Mar. 31, 2012 Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member]	Mar. 31, 2012 Greater than or equal to 0.90 to 1.0 [Member]	Mar. 31, 2012 Credit agreement [Member]	Dec. 31, 2011 Credit agreement [Member]	Mar. 31, 2012 6.5% Senior Subordinated Notes due 2018 [Member]	Dec. 31, 2011 6.5% Senior Subordinated Notes due 2018 [Member]	Mar. 31, 2012 7% Senior Subordinated Notes due 2014 [Member]	Dec. 31, 2011 7% Senior Subordinated Notes due 2014 [Member]
Long Term Debt
Total debt	$ 1,240,000	$ 1,380,000						$ 640,000	$ 780,000	$ 350,000	$ 350,000	$ 250,000	$ 250,000
Summary of margin rates
Ratio of Outstanding Borrowings to Borrowing Base			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
Applicable Margin for Base Rate Loans			0.50%	0.75%	1.00%	1.25%	1.50%
Applicable Margin for Eurodollar Loans			1.50%	1.75%	2.00%	2.25%	2.50%
Commitment Fee			0.375%	0.375%	0.50%	0.50%	0.50%

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Derivative Financial Instruments (Details 5) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Derivative assets:
Total derivative assets	$ 8,866
Not Designated as ASC 815 Hedges [Member]
Derivative assets:
Total derivative assets	13,958	19,306
Derivative liabilities:
Total derivative liabilities	131,606	121,410
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | Prepaid Expenses and Other [Member]
Derivative assets:
Total derivative assets	4,850	5,719
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | Other Long Term Assets [Member]
Derivative assets:
Total derivative assets	242
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | Current Derivative Liabilities [Member]
Derivative liabilities:
Total derivative liabilities	87,517	73,647
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | Non Current Derivative Liabilities [Member]
Derivative liabilities:
Total derivative liabilities	43,243	47,763
Embedded commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | Prepaid Expenses and Other [Member]
Derivative assets:
Total derivative assets		240
Embedded commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | Other Long Term Assets [Member]
Derivative assets:
Total derivative assets	8,866	13,347
Embedded commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | Current Derivative Liabilities [Member]
Derivative liabilities:
Total derivative liabilities	443
Embedded commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | Non Current Derivative Liabilities [Member]
Derivative liabilities:
Total derivative liabilities	$ 403

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Shareholders Equity and Noncontrolling Interest (Details Textual) (USD $)	1 Months Ended	3 Months Ended		12 Months Ended		3 Months Ended	1 Months Ended		3 Months Ended							3 Months Ended	12 Months Ended		12 Months Ended
	Jan. 31, 2011	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011	May 31, 2011	Mar. 31, 2012 Stock Appreciation Rights (SARs) [Member]	Jan. 31, 2012 Restricted Stock Units (RSUs) [Member]	Jan. 31, 2011 Restricted Stock Units (RSUs) [Member]	Mar. 31, 2012 Restricted Stock Units (RSUs) [Member]	Mar. 31, 2011 Restricted Stock Units (RSUs) [Member]	Mar. 31, 2012 Stock Options [Member] Y	Mar. 31, 2012 2003 Equity Incentive Plan [Member]	Mar. 31, 2011 2003 Equity Incentive Plan [Member]	Mar. 31, 2012 2003 Equity Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Y	May 31, 2011 Pre-adjustment [Member]	Mar. 31, 2012 Convertible Preferred Stock [Member]	Dec. 31, 2011 Convertible Preferred Stock [Member]	Jun. 30, 2009 Convertible Preferred Stock [Member]	Dec. 31, 2011 Convertible Preferred Stock [Member] Pre-adjustment [Member]
Additional Shareholders' Equity (Textual) [Abstract]
Number of common stock after approval to increase authorized shares		300,000,000		300,000,000	300,000,000										175,000,000
Interest rate on convertible perpetual preferred stock		6.25%		6.25%													6.25%
Common stock dividend, conversion price																	$ 21.70815		$ 43.4163
6.25% convertible perpetual preferred stock, shares issued		172,391		172,391														3,450,000
6.25% convertible perpetual preferred stock, shares issue Price per share																		$ 100.00
Dividend on preferred stock per share Per annum																$ 6.25
Liquidation preference per share of preferred stock																$ 100.00
All Preferred stock to be converted into shares of common stock at option of Company at any time On or after June15,2013																The Company may cause all outstanding shares of this preferred stock to be converted into shares of common stock if the closing price of our common stock equals or exceeds 120% of the then-prevailing conversion price for at least 20 trading days in a period of 30 consecutive trading days.
Preferred stock have no voting rights																The holders of preferred stock have no voting rights unless dividends payable on the preferred stock are in arrears for six or more quarterly periods.
Preferred stock remained outstanding		172,391		172,391												172,391
Two-for-one stock split				$ 100,000
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of options available for grant												1,066,089
Number of Share Granted									444,501	201,420
Grant date fair value of restricted stock awards, per share		$ 28.88	$ 34.15
Weighted Average Grant Date Fair Value, Granted							$ 29.45	$ 42.20
Unrecognized compensation cost									22,500,000		2,200,000
Weighted average period over which cost will recognized											2.3			2.6
Weighted average period over which cost will recognized									3 years
Maximum number of Shares per employee						600,000			300,000		600,000
Stock options granted under the equity plan		45,358										45,358	80,820
Shareholders Equity (Textual) [Abstract]
Minimum percentage of closing price of common stock upon which preferred stock will be converted into common shares		120.00%
Minimum trading days during which closing price of common shares equals or exceed prevailing conversion price		20 days
Minimum consecutive trading days during which closing price of common shares equals or exceed prevailing conversion price		30 days
Stock split approved	Two-for-one split of common stock to be effected in the form of a stock dividend to which stockholders of record on February 7, 2011 received one additional share of common stock for each share of common stock held.
Adjustments to additional paid in capital stock split per share		$ 0.001		$ 0.001
Common stock capital reserved for future issuance		2,978,323
Stock compensation expense recognized for restricted share awards and stock options		$ 4,200,000	$ 3,200,000

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Consolidated Balance Sheets (Unaudited) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 9,825	$ 15,811
Accounts receivable trade, net	293,863	262,515
Prepaid expenses and other	24,691	20,377
Total current assets	328,379	298,703
Oil and gas properties, successful efforts method:
Proved properties	7,335,250	7,221,550
Unproved properties	372,473	354,774
Other property and equipment	148,524	150,933
Total property and equipment	7,856,247	7,727,257
Less accumulated depreciation, depletion and amortization	(2,070,259)	(2,088,517)
Total property and equipment, net	5,785,988	5,638,740
Debt issuance costs	31,504	33,306
Other long-term assets	73,784	74,860
TOTAL ASSETS	6,219,655	6,045,609
Current liabilities:
Accounts payable trade	93,969	56,673
Accrued capital expenditures	121,969	142,827
Accrued liabilities and other	169,915	157,214
Revenues and royalties payable	119,567	103,894
Taxes payable	36,113	31,195
Derivative liabilities	87,960	73,647
Deferred income taxes	4,855	1,584
Total current liabilities	634,348	567,034
Long-term debt	1,240,000	1,380,000
Deferred income taxes	877,530	823,643
Derivative liabilities	43,646	47,763
Production Participation Plan liability	81,594	80,659
Asset retirement obligations	54,988	61,984
Deferred gain on sale	135,971	29,619
Other long-term liabilities	26,396	25,776
Total liabilities	3,094,473	3,016,478
Commitments and contingencies
Equity:
Preferred stock, $0.001 par value, 5,000,000 shares authorized; 6.25% convertible perpetual preferred stock, 172,391 shares issued and outstanding as of March 31, 2012 and December 31, 2011, aggregate liquidation preference of $17,239,100 at March 31, 2012
Common stock, $0.001 par value, 300,000,000 shares authorized; 118,565,350 issued and 117,617,777 outstanding as of March 31, 2012, 118,105,279 issued and 117,380,884 outstanding as of December 31, 2011	119	118
Additional paid-in capital	1,552,808	1,554,223
Accumulated other comprehensive income (loss)	(472)	240
Retained earnings	1,564,477	1,466,276
Total Whiting shareholders' equity	3,116,932	3,020,857
Noncontrolling interest	8,250	8,274
Total equity	3,125,182	3,029,131
TOTAL LIABILITIES AND EQUITY	$ 6,219,655	$ 6,045,609

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Fair Value Measurments (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Significant unobservable inputs
Total derivative assets	$ 8,866
Valuation Technique	Option model
Unobservable Input	Future prices of NYMEX crude oil after December 31, 2017
Range (per Bbl), minimum	93.81
Range (per Bbl), maximum	122.98

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Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Consolidated Statements of Comprehensive Income [Abstract]
Net of income tax expense	$ 415	$ 1,130

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Derivative Financial Instruments (Details) (Whiting Petroleum Corporation [Member])	Apr. 01, 2012 bbl
Crude oil [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	12,088,850
Natural gas [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	283,858
Apr - Dec 2012 [Member] | Crude oil [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	8,895,860
Apr - Dec 2012 [Member] | Crude oil [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	66.71
Apr - Dec 2012 [Member] | Crude oil [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	108.62
Apr - Dec 2012 [Member] | Natural gas [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	283,858
Apr - Dec 2012 [Member] | Natural gas [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	6.32
Apr - Dec 2012 [Member] | Natural gas [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	13.82
Jan - Dec 2013 [Member] | Crude oil [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	3,143,700
Jan - Dec 2013 [Member] | Crude oil [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	48.20
Jan - Dec 2013 [Member] | Crude oil [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	90.45
Jan - Dec 2013 [Member] | Natural gas [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held
Jan - Dec 2014 [Member] | Crude oil [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	49,290
Jan - Dec 2014 [Member] | Crude oil [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	80.00
Jan - Dec 2014 [Member] | Crude oil [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	122.50
Jan - Dec 2014 [Member] | Natural gas [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held

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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2012

Basis of Presentation [Abstract]

Description of Operations

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, natural gas and natural gas liquids primarily in the Rocky Mountains, Permian Basin, Mid-Continent, Michigan and Gulf Coast 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.

Consolidated Financial Statements

Consolidated Financial Statements—The unaudited 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. 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. These financial statements have been prepared in accordance with GAAP for interim financial reporting. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. Whiting’s 2011 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in Whiting’s 2011 Annual Report on Form 10-K.

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.

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Derivative Financial Instruments (Details 1) (Whiting USA Trust I [Member], Apr - Dec 2012 [Member])	Mar. 31, 2012 bbl
Crude Oil [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	77,930
Crude Oil [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	74.00
Crude Oil [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	141.87
Natural gas [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	283,858
Natural gas [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	6.32
Natural gas [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	13.82

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2012

Asset Retirement Obligations [Abstract]

Asset retirement obligations

Asset retirement obligation at January 1, 2012	$	69,721
Additional liability incurred		1,342
Revisions in estimated cash flows		(3,195	)
Accretion expense		1,907
Obligations on sold properties		(4	)
Liabilities settled		(2,983	)
Asset retirement obligation at March 31, 2012	$	66,788

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Consolidated Statements of Cash Flows (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 98,446	$ 19,414
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	156,120	107,728
Deferred income tax expense	57,573	10,760
Amortization of debt issuance costs and debt discount	2,340	2,127
Stock-based compensation	4,243	3,164
Amortization of deferred gain on sale	(3,753)	(3,367)
Undeveloped leasehold and oil and gas property impairments	17,834	7,638
Exploratory dry hole costs	251	2,902
Change in Production Participation Plan liability	935	(443)
Unrealized loss on derivative contracts	14,546	123,545
Other non-current	(5,853)	(815)
Changes in current assets and liabilities:
Accounts receivable trade	(31,348)	(44,303)
Prepaid expenses and other	(5,431)	(7,861)
Accounts payable trade and accrued liabilities	26,498	3,708
Revenues and royalties payable	15,673	(6,534)
Taxes payable	4,918	(3,608)
Net cash provided by operating activities	352,992	214,055
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash acquisition capital expenditures	(46,738)	(91,525)
Drilling and development capital expenditures	(492,810)	(284,752)
Proceeds from sale of oil and gas properties	2,922	21
Issuance of note receivable		(25,000)
Net proceeds from sale of 18,400,000 units in Whiting USA Trust II	323,574
Net cash used in investing activities	(213,052)	(401,256)
CASH FLOWS FROM FINANCING ACTIVITIES:
Contributions from noncontrolling interest		2,500
Preferred dividends paid	(269)	(270)
Long-term borrowings under credit agreement	520,000	470,000
Repayments of long-term borrowings under credit agreement	(660,000)	(290,000)
Debt issuance costs		(11)
Restricted stock used for tax withholdings	(5,657)	(8,944)
Net cash provided by (used in) financing activities	(145,926)	173,275
NET CHANGE IN CASH AND CASH EQUIVALENTS	(5,986)	(13,926)
CASH AND CASH EQUIVALENTS:
Beginning of period	15,811	18,952
End of period	9,825	5,026
NONCASH INVESTING ACTIVITIES:
Accrued capital expenditures	121,969	97,274
NONCASH FINANCING ACTIVITIES:
Contributions from noncontrolling interest		$ 5,833

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Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Consolidated Balance Sheets [Abstract]
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	5,000,000	5,000,000
6.25% convertible perpetual preferred stock, shares issued	172,391	172,391
6.25% convertible perpetual preferred stock, shares outstanding	172,391	172,391
6.25% convertible perpetual preferred stock, aggregate liquidation preference	$ 17,239,100
Convertible perpetual preferred stock	6.25%	6.25%
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares issued	118,565,350	118,105,279
Common stock, shares outstanding	117,617,777	117,380,884

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Deferred Compensation

3 Months Ended

Mar. 31, 2012

Deferred Compensation [Abstract]

DEFERRED COMPENSATION

7. 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 2%-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 three months ended March 31, 2012 and 2011 amounted to $18.9 million and $8.0 million, respectively, charged to general and administrative expense and $2.0 million and $0.9 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 March 31, 2012, the Company used three-year average historical NYMEX prices of $82.50 for crude oil and $4.01 for natural gas to estimate this liability. 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 March 31, 2012, 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 $167.6 million. This amount includes $15.0 million attributable to proved undeveloped oil and gas properties and $20.9 million relating to the short-term portion of the Plan liability, which has been accrued as a current payable to be paid in February 2013. 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):

Long-term Production Participation Plan liability at January 1	$	80,659
Change in liability for accretion, vesting, changes in estimates and new Plan year activity		21,815
Cash payments accrued as compensation expense and reflected as a current payable		(20,880	)
Long-term Production Participation Plan liability at March 31	$	81,594

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Document and Entity Information	3 Months Ended
	Mar. 31, 2012	Apr. 15, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	WHITING PETROLEUM CORP
Entity Central Index Key	0001255474
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		117,617,777

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Shareholders' Equity and Noncontrolling Interest

3 Months Ended

Mar. 31, 2012

Shareholders' Equity and Noncontrolling Interest [Abstract]

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST

8. 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 of March 31, 2012, however, only 172,391 shares of preferred stock remained outstanding.

Each holder of the preferred stock is 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 has been declared by Whiting’s board of directors. Each share of preferred stock has a liquidation preference of $100.00 per share plus accumulated and unpaid dividends and is convertible, at a holder’s option, into shares of Whiting’s common stock based on a conversion price of $21.70815, subject to adjustment upon the occurrence of certain events. The preferred stock is not redeemable by the Company. At any time on or after June 15, 2013, the Company may cause all outstanding shares of this preferred stock to be converted into shares of common stock if the closing price of our common stock equals or exceeds 120% of the then-prevailing conversion price for at least 20 trading days in a period of 30 consecutive trading days. The holders of preferred stock have no voting rights unless dividends payable on the preferred stock are in arrears for six or more quarterly periods.

Equity Incentive Plan—The Company maintains the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “Equity Plan”), pursuant to which 2,978,323 shares of the Company’s common stock have been reserved for issuance. 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 March 31, 2012, 1,066,089 shares of common stock remained available for grant under the Plan.

For the three months ended March 31, 2012 and 2011, total stock compensation expense recognized for restricted share awards and stock options was $4.2 million and $3.2 million, respectively.

Restricted Shares. Restricted stock awards for executive officers, directors and employees generally vest ratably over a three-year service period. The Company uses historical data and projections to estimate expected employee behaviors related to restricted stock forfeitures. The expected forfeitures are then included as part of the grant date estimate of compensation cost. 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 2012 and 2011, 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:

	2012			2011
Number of simulations		65,000			65,000
Expected volatility		51.9	%		75.8	%
Risk-free rate		0.35	%		1.00	%

The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation model was $29.45 per share in January 2012 and $42.20 per share in January 2011.

The following table shows a summary of the Company’s nonvested restricted stock as of March 31, 2012 as well as activity during the three months then ended:

	Number of Shares			Weighted Average Grant Date Fair Value
Restricted stock awards nonvested, January 1, 2012		724,395		$	29.88
Granted		568,661			34.20
Vested		(342,556	)		16.92
Forfeited		(2,927	)		51.59
Restricted stock awards nonvested, March 31, 2012		947,573		$	37.09

As of March 31, 2012, there was $22.5 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 2.6 years.

Stock Options. In January 2012 and 2011, 45,358 stock options and 80,820 stock options, respectively, were granted under the 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. 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 period:

	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 in January 2012 and $34.15 per share in January 2011.

The following table shows a summary of the Company’s stock options outstanding as of March 31, 2012 as well as activity during the three months then ended (aggregate intrinsic value presented in thousands):

	Number of Options		Weighted Average Exercise Price per Share		Aggregate Intrinsic Value		Weighted Average Remaining Contractual Term (in Years)
Options outstanding at January 1, 2012		377,336	$	26.09
Granted		45,358		51.22
Exercised		—		—	$	—
Forfeited or expired		—		—
Options outstanding at March 31, 2012		422,694	$	28.79	$	11,265.2		7.7
Options vested and expected to vest at March 31, 2012		422,694	$	28.79	$	11,265.2		7.7
Options exercisable at March 31, 2012		305,022	$	19.56	$	10,757.0		7.2

Unrecognized compensation cost as of March 31, 2012 related to unvested stock option awards was $2.2 million, which is expected to be recognized over a period of 2.3 years.

Noncontrolling Interest—The noncontrolling interest represents an unrelated third party’s 25% ownership interest in SWR. The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):

	Three Months Ended March 31,
	2012			2011
Balance at January 1	$	8,274		$	—
Contributions from noncontrolling interest		—			8,333
Net income (loss)		(24	)		—
Balance at March 31	$	8,250		$	8,333

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Consolidated Statements of Income (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
REVENUES AND OTHER INCOME:
Oil and natural gas sales	$ 558,697	$ 425,683
Gain on hedging activities	1,127	3,063
Amortization of deferred gain on sale	3,753	3,367
Interest income and other	129	108
Total revenues and other income	563,706	432,221
COSTS AND EXPENSES:
Lease operating	94,790	71,522
Production taxes	44,611	31,644
Depreciation, depletion and amortization	156,120	107,728
Exploration and impairment	27,578	22,237
General and administrative	34,368	18,413
Interest expense	18,456	14,458
Change in Production Participation Plan liability	935	(443)
Commodity derivative loss, net	29,403	134,438
Total costs and expenses	406,261	399,997
INCOME BEFORE INCOME TAXES	157,445	32,224
INCOME TAX EXPENSE:
Current	1,426	2,050
Deferred	57,573	10,760
Total income tax expense	58,999	12,810
NET INCOME	98,446	19,414
Net loss attributable to noncontrolling interest	24
NET INCOME AVAILABLE TO SHAREHOLDERS	98,470	19,414
Preferred stock dividends	(269)	(270)
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$ 98,201	$ 19,144
EARNINGS PER COMMON SHARE:
Basic	$ 0.84	$ 0.16
Diluted	$ 0.83	$ 0.16
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic	117,517	117,243
Diluted	118,896	117,834

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Acquisitions and Divestitures

3 Months Ended

Mar. 31, 2012

Acquisitions and Divestitures [Abstract]

ACQUISITIONS AND DIVESTITURES

2. ACQUISITIONS AND DIVESTITURES

2012 Acquisitions

On March 22, 2012, the Company completed the acquisition of approximately 13,300 net undeveloped acres in the Missouri Breaks prospect in Richland County, Montana for $33.3 million.

2012 Divestitures

On March 28, 2012, the Company completed an initial public offering of units of beneficial interest in Whiting USA Trust II (“Trust II”), selling 18,400,000 Trust II units at $20.00 per unit, providing net proceeds of $323.6 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 $129.5 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 18,400,000 trust 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. The conveyance of the net profits interest to Trust II consisted entirely of proved reserves of 10.61 MMBOE as of the January 1, 2012 effective date, representing 3% of Whiting’s proved reserves as of December 31, 2011 and 5% (or 4.5 MBOE/d) of its March 2012 average daily net production.

2011 Acquisitions

On July 28, 2011, the Company completed the acquisition of approximately 23,400 net acres and one well in the Missouri Breaks prospect 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.

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Basis of Presentation

3 Months Ended

Mar. 31, 2012

Basis of Presentation [Abstract]

BASIS OF PRESENTATION

1. BASIS OF PRESENTATION

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, natural gas and natural gas liquids primarily in the Rocky Mountains, Permian Basin, Mid-Continent, Michigan and Gulf Coast 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.

Consolidated Financial Statements—The unaudited 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. 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. These financial statements have been prepared in accordance with GAAP for interim financial reporting. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. Whiting’s 2011 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in Whiting’s 2011 Annual Report on Form 10-K.

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.

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2012

Long-Term Debt [Abstract]

Long Term Debt

	March 31, 2012		December 31, 2011
Credit agreement	$	640,000	$	780,000
6.5% Senior Subordinated Notes due 2018		350,000		350,000
7% Senior Subordinated Notes due 2014		250,000		250,000
Total debt	$	1,240,000	$	1,380,000

Summary of margin rates and commitment fees

Ratio of Outstanding Borrowings to Borrowing Base	Applicable Margin for Base Rate Loans			Applicable Margin for Eurodollar Loans			Commitment Fee
Less than 0.25 to 1.0		0.50	%		1.50	%		0.375	%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0		0.75	%		1.75	%		0.375	%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0		1.00	%		2.00	%		0.50	%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0		1.25	%		2.25	%		0.50	%
Greater than or equal to 0.90 to 1.0		1.50	%		2.50	%		0.50	%

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Income Taxes

3 Months Ended

Mar. 31, 2012

Income Taxes [Abstract]

INCOME TAXES

9. INCOME TAXES

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes for the three months ended March 31, 2012 and 2011 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to pre-tax income primarily because of state income taxes and estimated permanent differences.

The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent and temporary differences, and the likelihood of recovering deferred tax assets generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, additional information becomes known or as the tax environment changes.

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Derivative Financial Instruments

3 Months Ended

Mar. 31, 2012

Derivative Financial Instruments [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

5. 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, 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 and 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 I and Trust II derivatives, entered into to hedge forecasted crude oil and natural gas production revenues, as of April 1, 2012.

	Whiting Petroleum Corporation
	Contracted Volumes				Weighted Average NYMEX Price Collar Ranges
Period	Crude Oil (Bbl)		Natural Gas (Mcf)		Crude Oil (per Bbl)	Natural Gas (per Mcf)
Apr — Dec 2012		8,895,860		283,858	$ 66.71 - $108.62	$6.32 - $13.82
Jan — Dec 2013		3,143,700		—	$ 48.20 - $ 90.45	n/a
Jan — Dec 2014		49,290		—	$ 80.00 - $122.50	n/a
Total		12,088,850		283,858

Derivatives Conveyed to Whiting USA Trust I. In connection with the Company’s conveyance in April 2008 of a term net profits interest to Trust I and related sale of 11,677,500 Trust I 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 I, and therefore such payments will be included in Trust I’s calculation of net proceeds. Under the terms of the aforementioned conveyance, Whiting retains 10% of the net proceeds from the underlying properties. Whiting’s retention of 10% of these net proceeds, combined with its ownership of 2,186,389 Trust I units, results in third-party public holders of Trust I units receiving 75.8%, and Whiting retaining 24.2%, of the future economic results of commodity derivative contracts conveyed to Trust I. 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 I assets.

The 24.2% portion of Trust I derivatives that Whiting has retained the economic rights to (and which are also included in the table above) are as follows:

	Whiting Petroleum Corporation
	Contracted Volumes				Weighted Average NYMEX Price Collar Ranges
Period	Crude Oil (Bbl)		Natural Gas (Mcf)		Crude Oil (per Bbl)		Natural Gas (per Mcf)
Apr — Dec 2012		77,930		283,858	$	74.00 - $141.87	$	6.32 - $13.82

The 75.8% portion of Trust I derivative contracts of which Whiting has transferred the economic rights to third-party public holders of Trust I units (and which have not been reflected in the above tables) are as follows:

	Third-party Public Holders of Trust I Units
	Contracted Volumes				Weighted Average NYMEX Price Collar Ranges
Period	Crude Oil (Bbl)		Natural Gas (Mcf)		Crude Oil (per Bbl)	Natural Gas (per Mcf)
Apr — Dec 2012		244,096		889,109	$74.00 - $141.87	$6.32 - $13.82

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
	Contracted Crude Oil Volumes (Bbl)		Weighted Average NYMEX Price Collar Ranges for Crude Oil (per Bbl)
Apr — Dec 2012		42,930	$80.00 - $122.50
Jan — Dec 2013		53,700	$80.00 - $122.50
Jan — Dec 2014		49,290	$80.00 - $122.50
		145,920

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
	Contracted Crude Oil Volumes (Bbl)		Weighted Average NYMEX Price Collar Ranges for Crude Oil (per Bbl)
Apr — Dec 2012		386,370	$80.00 - $122.50
Jan — Dec 2013		483,300	$80.00 - $122.50
Jan — Dec 2014		443,610	$80.00 - $122.50
		1,313,280

Embedded Commodity Derivative Contracts—As of March 31, 2012, Whiting had entered into certain contracts for oil field goods or services, whereby the price adjustment clauses for such goods or services are linked to changes in NYMEX crude oil prices. The Company has determined that the portions of these contracts linked to NYMEX oil prices are not clearly and closely related to the host contracts, and the Company has therefore bifurcated these embedded pricing features from their host contracts and reflected them at fair value in the consolidated financial statements.

Drilling Rig Contracts. As of March 31, 2012, Whiting had entered into two contracts with drilling rig companies, whereby the rig day rates included price adjustment clauses that are linked to changes in NYMEX crude oil prices. These drilling rig contracts have termination dates of March 2014 and September 2014. The price adjustment formulas in the rig contracts stipulate that with every $10 increase or decrease in the price of NYMEX crude, the cost of drilling rig day rates to the Company will likewise increase or decrease by specific dollar amounts as set forth in each of the individual contracts. As of March 31, 2012, the aggregate estimated fair value of the embedded derivatives in these drilling rig contracts was a liability of $0.8 million.

As global crude oil prices increase or decrease, the demand for drilling rigs in North America similarly increases and decreases. Because the supply of onshore drilling rigs in North America is fairly inelastic, these changes in rig demand cause drilling rig day rates to increase or decrease in tandem with crude oil price fluctuations. When the Company enters into a long-term drilling rig contract that has a fixed rig day rate, which does not increase or decrease with changes in oil prices, the Company is exposed to the risk of paying higher than the market day rate for drilling rigs in a climate of declining oil prices. This in turn could have a negative impact on the Company’s oil and gas well economics. As a result, the Company reduces its exposure to this risk by entering into certain drilling contracts which have day rates that fluctuate in tandem with changes in oil prices.

CO ² Purchase 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. The price per Mcf of CO ² purchased under this agreement increases or decreases as the average price of NYMEX crude oil likewise increases or decreases. As of March 31, 2012, the estimated fair value of the embedded derivative in this CO² purchase contract was an asset of $8.9 million.

Although CO ² is not a commodity that is actively traded on a public exchange, the market price for CO ² 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 CO ² 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 on the consolidated balance sheet at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion. The following tables summarize the location and fair value amounts of all derivative instruments in the consolidated balance sheets (in thousands):

		Fair Value
Not Designated as ASC 815 Hedges	Balance Sheet Classification	March 31, 2012		December 31, 2011
Derivative assets:
Commodity contracts	Prepaid expenses and other	$	4,850	$	5,719
Embedded commodity contracts	Prepaid expenses and other		—		240
Commodity contracts	Other long-term assets		242		—
Embedded commodity contracts	Other long-term assets		8,866		13,347
Total derivative assets		$	13,958	$	19,306
Derivative liabilities:
Commodity contracts	Current derivative liabilities	$	87,517	$	73,647
Embedded commodity contracts	Current derivative liabilities		443		—
Commodity contracts	Non-current derivative liabilities		43,243		47,763
Embedded commodity contracts	Non-current derivative liabilities		403		—
Total derivative liabilities		$	131,606	$	121,410

The following tables summarize the effects of commodity derivatives instruments on the consolidated statements of income for the three months ended March 31, 2012 and 2011 (in thousands):

		Gain Reclassified from OCI into Income (Effective Portion)
ASC 815 Cash Flow		Three Months Ended March 31,
Hedging Relationships	Income Statement Classification	2012		2011
Commodity contracts	Gain on hedging activities	$	1,127	$	3,063

		Loss Recognized in Income
Not Designated as		Three Months Ended March 31,
ASC 815 Hedges	Income Statement Classification	2012		2011
Commodity contracts	Commodity derivative loss, net	$	23,837	$	131,357
Embedded commodity contracts	Commodity derivative loss, net		5,566		3,081
Total		$	29,403	$	134,438

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 current or former lenders under Whiting’s credit agreement. At the time Whiting enters into derivative contracts, 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.

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Long-Term Debt

3 Months Ended

Mar. 31, 2012

Long-Term Debt [Abstract]

LONG-TERM DEBT

3. LONG-TERM DEBT

Long-term debt consisted of the following at March 31, 2012 and December 31, 2011 (in thousands):

	March 31, 2012		December 31, 2011
Credit agreement	$	640,000	$	780,000
6.5% Senior Subordinated Notes due 2018		350,000		350,000
7% Senior Subordinated Notes due 2014		250,000		250,000
Total debt	$	1,240,000	$	1,380,000

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. As of March 31, 2012, this credit facility had a borrowing base of $1.5 billion with $858.6 million of available borrowing capacity, which is net of $640.0 million in borrowings and $1.4 million in letters of credit 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 its 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 March 31, 2012, $48.6 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 are included as a component of interest expense. At March 31, 2012, the weighted average interest rate on the outstanding principal balance under the credit agreement was 2.1%.

Ratio of Outstanding Borrowings to Borrowing Base	Applicable Margin for Base Rate Loans			Applicable Margin for Eurodollar Loans			Commitment Fee
Less than 0.25 to 1.0		0.50	%		1.50	%		0.375	%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0		0.75	%		1.75	%		0.375	%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0		1.00	%		2.00	%		0.50	%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0		1.25	%		2.25	%		0.50	%
Greater than or equal to 0.90 to 1.0		1.50	%		2.50	%		0.50	%

The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders. Except for limited exceptions, which include the payment of dividends on the Company’s 6.25% convertible perpetual preferred stock, the credit agreement also restricts our 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 March 31, 2012, total restricted net assets were $2,961.0 million, and the amount of retained earnings free from restrictions was $17.8 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 4.25 to 1.0 for quarters ending prior to and on December 31, 2012 and 4.0 to 1.0 for quarters ending March 31, 2013 and thereafter 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 March 31, 2012.

The obligations of Whiting Oil and Gas under the amended 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 Subordinated Notes—In October 2005, the Company issued at par $250.0 million of 7% Senior Subordinated Notes due February 2014. The estimated fair value of these notes was $266.9 million as of March 31, 2012, based on quoted market prices for these same debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy.

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 $372.3 million as of March 31, 2012, based on quoted market prices for these same debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy.

The notes are unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the Company’s senior debt, which currently consists of Whiting Oil and Gas’ credit agreement. The Company’s obligations under the 2014 notes are fully, unconditionally, jointly and severally guaranteed by the Company’s 100%-owned subsidiaries, Whiting Oil and Gas and Whiting Programs, Inc. (the “2014 Guarantors”). Additionally, the Company’s obligations under the 2018 notes are fully, unconditionally, jointly and severally guaranteed by the Company’s 100%-owned subsidiary, Whiting Oil and Gas (collectively with the 2014 Guarantors, the “Guarantors”). Any subsidiaries other than the Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S-X of the Securities and Exchange Commission. Whiting Petroleum Corporation has no assets or operations independent of this debt and its investments in guarantor subsidiaries.

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2012

Asset Retirement Obligations [Abstract]

ASSET RETIREMENT OBLIGATIONS

4. ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations represent the 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 March 31, 2012 and December 31, 2011 were $11.8 million and $7.7 million, respectively, and are included in accrued liabilities and other. Revisions to the liability could 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 three months ended March 31, 2012 (in thousands):

Asset retirement obligation at January 1, 2012	$	69,721
Additional liability incurred		1,342
Revisions in estimated cash flows		(3,195	)
Accretion expense		1,907
Obligations on sold properties		(4	)
Liabilities settled		(2,983	)
Asset retirement obligation at March 31, 2012	$	66,788

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Fair Value Measurements

3 Months Ended

Mar. 31, 2012

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

6. FAIR VALUE MEASURMENTS

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 March 31, 2012 and December 31, 2011, 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 March  31, 2012
Financial Assets
Commodity derivatives—current	$	—	$	4,850	$	—	$	4,850
Commodity derivatives—non-current		—		242		—		242
Embedded commodity derivatives—non-current		—		—		8,866		8,866
Total financial assets	$	—	$	5,092	$	8,866	$	13,958
Financial Liabilities
Commodity derivatives—current	$	—	$	87,517	$	—	$	87,517
Embedded commodity derivatives—current				443		—		443
Commodity derivatives—non-current		—		43,243		—		43,243
Embedded commodity derivatives—non-current				403		—		403
Total financial liabilities	$	—	$	131,606	$	—	$	131,606
	Level 1		Level 2		Level 3		Total Fair Value December 31, 2011
Financial Assets
Commodity derivatives—current	$	—	$	5,719	$	—	$	5,719
Embedded commodity derivatives—current		—		240		—		240
Embedded commodity derivatives—non-current		—		367		12,980		13,347
Total financial assets	$	—	$	6,326	$	12,980	$	19,306
Financial Liabilities
Commodity derivatives—current	$	—	$	73,647	$	—	$	73,647
Commodity derivatives—non-current		—		47,763		—		47,763
Total financial liabilities	$	—	$	121,410	$	—	$	121,410

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 primarily of costless collars for crude oil and natural gas. The Company’s costless collars are valued based on a market approach. These models consider various assumptions, including 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 counterparties’ valuations to assess the reasonableness of its own valuations.

Embedded Commodity Derivatives. Embedded commodity derivatives relate to long-term drilling rig contracts as well as a long-term CO² purchase contract, which all have price adjustment clauses that are linked to changes in NYMEX crude oil prices. Whiting has determined that the portions of these contracts linked to NYMEX oil prices are not clearly and closely related to the host drilling contracts, and the Company has therefore bifurcated these embedded pricing features from their host contracts and reflected them at fair value in its consolidated financial statements. These embedded commodity derivatives are valued based on an income approach. These option models consider 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 valuation of the drilling rig contracts 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 the fair value measurements of the drilling rig contracts are therefore designated as Level 2 within the valuation hierarchy.

The assumptions used in the CO ² contract valuation, however, 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 to determine the fair value of the embedded commodity derivative instrument designated as Level 3. The Company reviews these valuations (including the related model inputs and assumptions) and analyzes changes in fair value measurements between periods. The Company corroborates such inputs, calculations and fair value changes using various methodologies.

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 three months ended March 31, 2012 (in thousands):

	Three Months Ended March 31, 2012 (2)
Fair value asset, beginning of period	$	12,980
Unrealized gains (losses) on embedded commodity derivative contracts included in earnings (1)		(4,114	)
Transfers into (out of) Level 3		—
Fair value asset, end of period	$	8,866

(1) Included in commodity derivative loss, net in the consolidated statements of income.

(2) There were no recurring fair value measurements designated as Level 3 during the three months ended March 31, 2011.

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 March 31, 2012 (in thousands)		Valuation Technique	Unobservable Input	Range (per Bbl)
Embedded commodity derivative	$	8,866	Option model	Future prices of NYMEX crude oil after December 31, 2017	$	93.81-$122.98

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 CO ² purchase contract are the future prices of NYMEX crude oil from 2018 to 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. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company did not recognize any nonrecurring fair value adjustments during the 2012 or 2011 reporting periods presented.

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Asset Retirement Obligations (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Asset retirement obligations
Asset retirement obligation at January 1	$ 69,721,000
Additional liability incurred	1,342,000
Revisions in estimated cash flows	(3,195,000)
Accretion expense	1,907,000
Obligations on sold properties	(4,000)
Liabilities settled	(2,983,000)
Asset retirement obligation at December 31	66,788,000
Asset Retirement Obligation (Textual) [Abstract]
Asset retirement obligations, current portion	$ 11,800,000	$ 7,700,000

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Shareholders Equity and Noncontrolling Interest (Details 3) (USD $)	3 Months Ended
	Mar. 31, 2012 Y
Summary of stock options outstanding
Options outstanding, beginning of period	377,336
Granted, Number of Options	45,358
Exercised, Number of Options
Forfeited or expired, Number of Options
Options outstanding, ending period	422,694
Options vested and expected to vest ending period, Number of Options	422,694
Options exercisable, Number of Options	305,022
Options outstanding, beginning of period, weighted average exercise price per share	$ 26.09
Granted, Weighted Average Exercise Price per Share	$ 51.22
Exercised, Weighted Average Exercise Price per Share
Forfeited or expired, Weighted Average Exercise Price per Share
Options outstanding, ending period, Weighted Average Exercise Price per Share	$ 28.79
Options vested and expected to vest, Weighted Average Exercise Price per Share	$ 28.79
Number of options exercisable, Weighted Average Exercise Price per Share	$ 19.56
Exercised, Aggregate Intrinsic Value
Options outstanding ending period, Aggregate Intrinsic Value	11,265,200
Options vested and expected to vest, Aggregate Intrinsic Value	11,265,200
Options exercisable, Aggregate Intrinsic Value	$ 10,757,000
Options outstanding, Weighted Average Remaining Contractual Term (in Years)	7.7
Options outstanding, ending period, Weighted Average Remaining Contractual Term (in Years)	7.7
Options vested and expected to vest, Weighted Average Remaining Contractual Term (in Years)	7.7
Options exercisable, Weighted Average Remaining Contractual Term (in Years)	7.2

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Adopted and Recently Issued Accounting Pronouncements

3 Months Ended

Mar. 31, 2012

Adopted and Recently Issued Accounting Pronouncements [Abstract]

ADOPTED AND RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

11. ADOPTED AND RECENTLY ISSUED ACCOUNTING 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. These amendments are not having a significant impact on companies applying GAAP. ASU 2011-04 was effective for interim and annual 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 defers 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 previously 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. ASU 2011-11 is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

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Fair Value Measurments (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value Measurements [Abstract]

Fair value assets and liabilities measured on a recurring basis

	Level 1		Level 2		Level 3		Total Fair Value March  31, 2012
Financial Assets
Commodity derivatives—current	$	—	$	4,850	$	—	$	4,850
Commodity derivatives—non-current		—		242		—		242
Embedded commodity derivatives—non-current		—		—		8,866		8,866
Total financial assets	$	—	$	5,092	$	8,866	$	13,958
Financial Liabilities
Commodity derivatives—current	$	—	$	87,517	$	—	$	87,517
Embedded commodity derivatives—current				443		—		443
Commodity derivatives—non-current		—		43,243		—		43,243
Embedded commodity derivatives—non-current				403		—		403
Total financial liabilities	$	—	$	131,606	$	—	$	131,606
	Level 1		Level 2		Level 3		Total Fair Value December 31, 2011
Financial Assets
Commodity derivatives—current	$	—	$	5,719	$	—	$	5,719
Embedded commodity derivatives—current		—		240		—		240
Embedded commodity derivatives—non-current		—		367		12,980		13,347
Total financial assets	$	—	$	6,326	$	12,980	$	19,306
Financial Liabilities
Commodity derivatives—current	$	—	$	73,647	$	—	$	73,647
Commodity derivatives—non-current		—		47,763		—		47,763
Total financial liabilities	$	—	$	121,410	$	—	$	121,410

Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy

	Three Months Ended March 31, 2012 (2)
Fair value asset, beginning of period	$	12,980
Unrealized gains (losses) on embedded commodity derivative contracts included in earnings (1)		(4,114	)
Transfers into (out of) Level 3		—
Fair value asset, end of period	$	8,866

Significant unobservable inputs used in the fair value measurement

	Fair Value at March 31, 2012 (in thousands)		Valuation Technique	Unobservable Input	Range (per Bbl)
Embedded commodity derivative	$	8,866	Option model	Future prices of NYMEX crude oil after December 31, 2017	$	93.81-$122.98

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Shareholders Equity and Noncontrolling Interest (Details 1) (Restricted Stock [Member], USD $)	3 Months Ended
	Mar. 31, 2012
Restricted Stock [Member]
Summary of nonvested restricted stock
Restricted stock awards nonvested, Number of Shares, Beginning Balance	724,395
Number of Share Granted	568,661
Number of Share Vested	(342,556)
Number of Share Forfeited	(2,927)
Restricted stock awards nonvested, Number of Shares, Ending Balance	947,573
Restricted stock awards nonvested, Weighted Average Grant Date Fair Value, Beginning Balance	$ 29.88
Weighted Average Grant Date Fair Value, Granted	$ 34.20
Weighted Average Grant Date Fair Value, Vested	$ 16.92
Weighted Average Grant Date Fair Value, Forfeited	$ 51.59
Restricted stock awards nonvested, Weighted Average grant Date Fair Value, Ending Balance	$ 37.09

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Derivative Financial Instruments (Details 6) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Not Designated as ASC 815 Hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Loss Recognized in Income	$ 29,403	$ 134,438
Commodity contracts [Member] | Gain on hedging activities [Member] | ASC 815 Cash Flow Hedging Relationship [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Income as of December 31, 2011 from Derivative Contracts	1,127	3,063
Commodity contracts [Member] | Commodity derivative gain loss net [Member] | Not Designated as ASC 815 Hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Loss Recognized in Income	23,837	131,357
Embedded commodity contracts [Member] | Commodity derivative gain loss net [Member] | Not Designated as ASC 815 Hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Loss Recognized in Income	$ 5,566	$ 3,081

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Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Consolidated Statements of Comprehensive Income [Abstract]
NET INCOME	$ 98,446		$ 19,414
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
OCI amortization on de-designated hedges	(712)	[1]	(1,934)	[1]
Total other comprehensive loss, net of tax	(712)		(1,934)
COMPREHENSIVE INCOME	97,734		17,480
Comprehensive loss attributable to noncontrolling interest	24
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING	$ 97,758		$ 17,480

[1] Presented net of income tax expense of $415 and $1,130 for the three months ended March 31, 2012 and 2011, respectively.

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Consolidated Statements of Equity (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
OCI amortization on de-designated hedges, taxes	$ 415	$ 1,130
Accumulated Other Comprehensive Income (Loss)
OCI amortization on de-designated hedges, taxes	415	1,130
Total Whiting Shareholders' Equity
OCI amortization on de-designated hedges, taxes	$ 415	$ 1,130

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Deferred Compensation (Tables)

3 Months Ended

Mar. 31, 2012

Deferred Compensation [Abstract]

Changes in Estimated Long-Term Liability

Long-term Production Participation Plan liability at January 1	$	80,659
Change in liability for accretion, vesting, changes in estimates and new Plan year activity		21,815
Cash payments accrued as compensation expense and reflected as a current payable		(20,880	)
Long-term Production Participation Plan liability at March 31	$	81,594

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Derivative Financial Instruments (Details 3) (Whiting US Trust II Units [Member], Crude oil [Member])	Mar. 31, 2012 bbl
Derivative [Line Items]
Number of Price Risk Derivatives Held	145,920
Apr - Dec 2012 [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	42,930
Apr - Dec 2012 [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	80.00
Apr - Dec 2012 [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	122.50
Jan - Dec 2013 [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	53,700
Jan - Dec 2013 [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	80.00
Jan - Dec 2013 [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	122.50
Jan - Dec 2014 [Member]
Derivative [Line Items]
Number of Price Risk Derivatives Held	49,290
Jan - Dec 2014 [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Floor Price	80.00
Jan - Dec 2014 [Member] | Maximum [Member]
Derivative [Line Items]
Derivative, Cap Price	122.50

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Earnings Per Share

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

EARNINGS PER SHARE

10. EARNINGS PER SHARE

The reconciliations between basic and diluted earnings per share are as follows (in thousands, except per share data):

	Three Months Ended March 31,
	2012			2011
Basic Earnings Per Share
Numerator:
Net income available to shareholders	$	98,470		$	19,414
Preferred stock dividends		(269	)		(270	)
Net income available to common shareholders, basic	$	98,201		$	19,144
Denominator:
Weighted average shares outstanding, basic		117,517			117,243
Diluted Earnings Per Share
Numerator:
Net income available to common shareholders, basic	$	98,201		$	19,144
Preferred stock dividends		269			—
Adjusted net income available to common shareholders, diluted	$	98,470		$	19,144
Denominator:
Weighted average shares outstanding, basic		117,517			117,243
Restricted stock and stock options		585			591
Convertible perpetual preferred stock		794			—
Weighted average shares outstanding, diluted		118,896			117,834
Earnings per common share, basic	$	0.84		$	0.16
Earnings per common share, diluted	$	0.83		$	0.16

For the three months ended March 31, 2012, the diluted earnings per share calculation excludes the effect of 7,006 common shares for stock options that were out-of-the-money. For the three months ended March 31, 2011, the diluted earnings per share calculation excludes the effect of 794,330 incremental common shares (which were issuable upon the conversion of perpetual preferred stock as of a January 1, 2011 assumed conversion date) because their effect was anti-dilutive.