Edgar Filing: WHITING PETROLEUM CORP

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2006


o		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		(I.R.S. Employer
of incorporation or organization)		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 þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).


Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Number of shares of the registrant’s common stock outstanding at July 17, 2006: 36,951,365 shares.

TABLE OF CONTENTS


	PART I — FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (Unaudited)	1

	Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005	1

	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2006 and 2005	3

	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005	4

	Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the Year Ended December 31, 2005 and the Six Months Ended June 30, 2006	5

	Condensed Notes to Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34

Item 4.	Controls and Procedures	36

	PART II — OTHER INFORMATION

Item 1A.	Risk Factors	37

Item 4.	Submission of Matters to a Vote of Security Holders	37

Item 6.	Exhibits	37
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Written Statement of CEO Pursuant to Section 1350
Written Statement of CFO Pursuant to Section 1350

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands)


	June 30,			December 31,
	2006			2005
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	12,073		$	10,382
Accounts receivable trade, net		92,155			101,066
Deferred income taxes		12,911			15,121
Prepaid expenses and other		9,147			5,595


Total current assets		126,286			132,164

PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties		2,593,799			2,353,372
Unproved properties		31,260			21,671
Other property and equipment		38,687			26,235


Total property and equipment		2,663,746			2,401,278

Less accumulated depreciation, depletion and amortization		(411,109	)		(338,420	)


Total property and equipment-net		2,252,637			2,062,858


DEBT ISSUANCE COSTS		21,456			23,660

OTHER LONG-TERM ASSETS		17,159			16,514


TOTAL	$	2,417,538		$	2,235,196

See condensed notes to consolidated financial statements.

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share data)


	June 30,			December 31,
	2006			2005
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	79,468		$	68,033
Accrued interest		8,966			11,894
Oil and gas sales payable		23,127			21,154
Accrued employee compensation and benefits		11,476			15,351
Production taxes payable		15,999			13,259
Current portion of tax sharing liability		4,254			4,254
Current portion of derivative liability		28,845			34,569


Total current liabilities		172,135			168,514

NON-CURRENT LIABILITIES:
Long-term debt		923,208			875,098
Asset retirement obligations		33,108			32,246
Production Participation Plan liability		23,431			19,287
Tax sharing liability		25,626			24,576
Deferred income taxes		127,008			91,577
Long-term derivative liability		29,415			21,817
Other long-term liabilities		6,370			4,219


Total non-current liabilities		1,168,166			1,068,820

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY:
Common stock, $.001 par value; 75,000,000 shares authorized, 36,951,365 and 36,841,823 shares issued and outstanding as of June 30, 2006 and December 31, 2005, respectively		37			37
Additional paid-in capital		752,718			753,093
Accumulated other comprehensive loss		(35,772	)		(34,620	)
Deferred compensation		—			(2,031	)
Retained earnings		360,254			281,383


Total stockholders’ equity		1,077,237			997,862


TOTAL	$	2,417,538		$	2,235,196

See condensed notes to consolidated financial statements.

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(In thousands, except per share data)


	Three Months Ended June 30,					Six Months Ended June 30,
	2006		2005			2006			2005
REVENUES AND OTHER INCOME:
Oil and natural gas sales	$	203,643	$	115,978		$	393,509		$	221,443
Gain (loss) on oil and natural gas hedging activities		40		(4,890	)		(9,484	)		(6,945	)
Interest income and other		338		35			627			166

Total revenues and other income		204,021		111,123			384,652			214,664


COSTS AND EXPENSES:
Lease operating		44,657		22,110			89,052			42,939
Production taxes		12,394		7,915			24,330			14,455
Depreciation, depletion and amortization		38,909		20,735			74,209			41,082
Exploration and impairment		9,214		6,058			16,256			7,357
General and administrative		9,638		7,131			19,249			13,273
Change in Production Participation Plan liability		2,069		(417	)		4,144			269
Interest expense		18,627		8,122			35,601			13,378

Total costs and expenses		135,508		71,654			262,841			132,753

INCOME BEFORE INCOME TAXES		68,513		39,469			121,811			81,911

INCOME TAX EXPENSE:
Current		2,581		3,099			4,612			4,737
Deferred		20,052		12,132			38,328			26,881

Total income tax expense		22,633		15,231			42,940			31,618

NET INCOME	$	45,880	$	24,238		$	78,871		$	50,293


NET INCOME PER COMMON SHARE, BASIC	$	1.25	$	0.82		$	2.15		$	1.69


NET INCOME PER COMMON SHARE, DILUTED	$	1.25	$	0.82		$	2.14		$	1.69


WEIGHTED AVERAGE SHARES OUTSTANDING, BASIC		36,748		29,681			36,737			29,673


WEIGHTED AVERAGE SHARES OUTSTANDING, DILUTED		36,812		29,699			36,783			29,698

See condensed notes to consolidated financial statements.

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)


	Six Months Ended
	June 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	78,871		$	50,293
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		74,209			41,082
Deferred income taxes		38,328			26,881
Amortization of debt issuance costs and debt discount		2,632			1,697
Accretion of tax sharing liability		1,050			1,240
Stock-based compensation		1,854			1,546
Exploratory dry hole costs and leasehold impairments		5,897			3,778
Change in Production Participation Plan liability		4,144			269
Other non-current		(1,685	)		(406	)
Changes in assets and liabilities:
Accounts receivable trade		8,911			6,633
Prepaid expenses and other		(3,552	)		1,078
Accounts payable		16,227			43
Accrued interest		(2,928	)		2,795
Other liabilities		838			2,871

Net cash provided by operating activities		224,796			139,800

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash acquisition capital expenditures		(33,741	)		(78,588	)
Drilling capital expenditures		(239,154	)		(54,774	)
Acquisition of Partnership interests, net of cash acquired of $26		—			(30,433	)

Net cash used in investing activities		(272,895	)		(163,795	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of 7.25% Senior Subordinated debt due 2013		—			216,715
Issuance of long-term debt under credit agreement		120,000			60,000
Payments on long-term debt under credit agreement		(70,000	)		(235,000	)
Debt issuance costs		(103	)		(3,777	)
Restricted stock used for tax withholdings		(367	)		(174	)
Tax effect from restricted stock vesting		260			192

Net cash provided by financing activities		49,790			37,956


NET CHANGE IN CASH AND CASH EQUIVALENTS		1,691			13,961
CASH AND CASH EQUIVALENTS:
Beginning of period		10,382			1,660

End of period	$	12,073		$	15,621

SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for income taxes	$	3,637		$	5,277

Cash paid for interest	$	35,052		$	7,075

NONCASH INVESTING ACTIVITIES:
Decrease in accrued capital expenditures	$	4,793		$	785

See condensed notes to consolidated financial statements.

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (Unaudited)

(In thousands)


									Accumulated
	Common Stock					Additional			Other								Total
						Paid-in			Comprehensive			Deferred			Retained		Stockholders’			Comprehensive
	Shares			Amount		Capital			Income (Loss)			Compensation			Earnings		Equity			Income
BALANCES—January 1, 2005		29,718		$	30	$	455,635		$	(1,025	)	$	(1,715	)	$	159,461	$	612,386
Net income		—			—		—			—			—			121,922		121,922		$	121,922
Change in derivative instrument fair value, net of related taxes		—			—		—			(54,089	)		—			—		(54,089	)		(54,089	)
Realized loss on settled derivative contracts, net of related taxes		—			—		—			20,494			—			—		20,494			20,494
Restricted stock issued		85			—		3,407			—			(3,407	)		—		—			—
Restricted stock forfeited		(9	)		—		(230	)		—			230			—		—			—
Restricted stock used for tax withholdings		(6	)		—		(241	)		—			—			—		(241	)		—
Tax effect from restricted stock vesting		—			—		237			—			—			—		237			—
Issuance of stock – secondary offering		6,612			7		227,110			—			—			—		277,117			—
Issuance of stock – North Ward Estes acquisition		442			—		17,175			—			—			—		17,175			—
Amortization of deferred compensation		—			—		—			—			2,861			—		2,861			—


BALANCES—December 31, 2005		36,842			37		753,093			(34,620	)		(2,031	)		281,383		997,862		$	88,327

Net income		—			—		—			—			—			78,871		78,871			78,871
Change in derivative instrument fair value, net of related taxes		—			—		—			(6,975	)		—			—		(6,975	)		(6,975	)
Realized loss on settled derivative contracts, net of related taxes		—			—		—			5,823			—			—		5,823			5,823
Restricted stock issued		126			—		—			—			—			—		—			—
Restricted stock forfeited		(9	)		—		—			—			—			—		—			—
Restricted stock used for tax withholdings		(8	)		—		(367	)		—			—			—		(367	)		—
Tax effect from restricted stock vesting		—			—		260			—			—			—		260			—
Adoption of SFAS 123R		—			—		(2,122	)		—			2,031			—		(91	)		—
Stock-based compensation		—			—		1,854			—			—			—		1,854			—


BALANCES—June 30, 2006		36,951		$	37	$	752,718		$	(35,772	)	$	—		$	360,254	$	1,077,237		$	77,719

See condensed notes to consolidated financial statements.

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(In thousands, except per share data)

1.		BASIS OF PRESENTATION

		*Description of Operations*—Whiting Petroleum Corporation (“Whiting” or the “Company”) is an independent oil and gas company that acquires, develops and explores for crude oil, natural gas and natural gas liquids primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States.

		*Consolidated Financial Statements*— The unaudited consolidated financial statements include the accounts of Whiting and its subsidiaries, all of which are wholly owned. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial reporting. All significant intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, all material adjustments considered necessary for a fair presentation of the Company’s interim results have been reflected. Whiting’s 2005 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 has been no material change to the information disclosed in the notes to consolidated financial statements included in Whiting’s 2005 Annual Report on Form 10-K.

		*Earnings Per Share*—Statement of Financial Accounting Standards No. 128, Earnings Per Share, requires presentation of “basic” and “diluted” earnings per share. Basic net income per common share of stock is calculated by dividing net income by the weighted average number of common shares outstanding during each period. Diluted net income per common share of stock is calculated by dividing net income by the weighted average number of common shares outstanding and other dilutive securities. The only securities considered dilutive are the Company’s unvested restricted stock awards.

		*Reclassifications*—Certain prior period balances were reclassified to conform to the current year presentation, and such reclassifications had no impact on net income or stockholders’ equity previously reported.

		*Change in Accounting Principle—In December 2004, the Financial Accounting Standards Board issued SFAS No. 123(R), Share-Based Payment* (“SFAS 123R”). This Statement is a revision of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), and supersedes Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”), and its related implementation guidance. SFAS 123R requires a company to measure the grant date fair value of equity awards given to employees in exchange for services and recognize that cost, less estimated forfeitures, over the period that such services are performed. The Company adopted SFAS 123R on January 1, 2006 using the modified prospective transition method.

		Prior to adopting SFAS 123R, the Company accounted for stock-based compensation under SFAS 123, whereby the Company’s policy was to recognize actual forfeitures of restricted stock only when they occurred rather than estimate them at the grant date and subsequently true-up estimated forfeitures to actuals. SFAS 123R requires companies to include forfeitures as part of the grant date estimate of compensation cost. Under the modified prospective method of adopting SFAS 123R, compensation cost recognized for the six months ended June 30, 2006 includes (a) compensation cost for all restricted stock awards granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value, less estimated forfeitures, and (b) compensation cost for all share-based payments granted and vested subsequent to January 1, 2006, based on the grant date fair value, less estimated forfeitures. A cumulative effect of change in accounting principle to recognize the impact of including forfeitures, as part of the grant date estimate of compensation cost for all restricted stock awards granted prior to January 1, 2006, resulted in an insignificant credit to income for the six months ended June 30, 2006. In accordance with the modified prospective method, prior period results have not been restated.

		For the three and six months ended June 30, 2006, the Company recognized share-based compensation costs of $0.9 million and $1.6 million, respectively, in general and administrative expenses and $0.2 million and $0.3 million, respectively, in exploration expenses in the Company’s consolidated statement of income. The Company did not recognize an income tax benefit for share-based compensation for the three months ended June 30, 2006, but did recognize $0.3 million in income tax benefits relating to share-based compensation for the six months ended June 30, 2006. The Company did not capitalize any share-based compensation costs for the six months ended June 30, 2006.

		The adoption of SFAS 123R had a minimal impact on the Company’s income before income taxes and net income, and had no effect on basic or diluted earnings per share, for the three and six months ended June 30, 2006, as presented in the Company’s consolidated statements of income.

		Under the provisions of SFAS 123R, the recognition of deferred compensation at the date restricted stock is granted is no longer required. Therefore, in the first quarter of 2006, the amount that had been previously recorded as “Deferred compensation” in the Company’s consolidated balance sheets was reversed in its entirety to additional paid-in capital.

		In addition, the adoption of SFAS 123R required that the Company classify certain tax benefits, which result from tax deductions in excess of compensation cost recognized for book purposes, as financing cash flows rather than operating cash flows.


2.		ACQUISITIONS

		There have been no significant acquisitions in 2006.

		2005 Acquisitions

		*North Ward Estes and Ancillary Properties*—On October 4, 2005, the Company acquired the operated interest in the North Ward Estes field in Ward and Winkler counties, Texas, and certain smaller fields located in the Permian Basin. The purchase price was $459.2 million, consisting of $442.0 million in cash and 441,500 shares of the Company’s common stock, for estimated proved reserves of approximately 82.1 MMBOE as of the acquisition effective date of July 1, 2005, resulting in a cost of approximately $5.58 per BOE of estimated proved reserves. The average daily production from the properties was approximately 4.6 MBOE/d as of the acquisition effective date. The Company funded the

		cash portion of the purchase price with the net proceeds from the Company’s public offering of common stock and private placement of 7% Senior Subordinated Notes due 2014, both of which closed on October 4, 2005.

		*Postle Field*—On August 4, 2005, the Company acquired the operated interest in producing oil and natural gas fields located in the Oklahoma Panhandle. The purchase price was $343.0 million for estimated proved reserves of approximately 40.3 MMBOE as of the acquisition effective date of July 1, 2005, resulting in a cost of approximately $8.52 per BOE of estimated proved reserves. The average daily production from the properties was approximately 4.2 MBOE/d as of the acquisition effective date. The Company funded the acquisition through borrowings under Whiting Oil and Gas’ credit agreement.

		*Limited Partnership Interests*—On June 23, 2005, the Company acquired all of the limited partnership interests in three institutional partnerships managed by its wholly-owned subsidiary, Whiting Programs, Inc. The partnership properties are located in Louisiana, Texas, Arkansas, Oklahoma and Wyoming. The purchase price was $30.5 million for estimated proved reserves of approximately 2.9 MMBOE as of the acquisition effective date of January 1, 2005, resulting in a cost of approximately $10.52 per BOE of estimated proved reserves. The average daily production from the properties was 0.7 MBOE/d as of the acquisition effective date. The Company funded the acquisition with cash on hand.

		*Green River Basin*—On March 31, 2005, the Company acquired operated interests in five producing natural gas fields in the Green River Basin of Wyoming. The purchase price was $65.0 million for estimated proved reserves of approximately 8.4 MMBOE as of the acquisition effective date of March 1, 2005, resulting in a cost of $7.74 per BOE of estimated proved reserves. The average daily production from the properties was approximately 1.1 MBOE/d as of the acquisition effective date. The Company funded the acquisition through borrowings under Whiting Oil and Gas’ credit agreement and with cash on hand.

		As these acquisitions were recorded using the purchase method of accounting, the results of operations from the acquisitions are included with the Company’s results from the respective acquisition dates noted above. The table below summarizes the allocation of the purchase price for each 2005 purchase transaction based on the acquisition date fair values of the assets acquired and the liabilities assumed (in thousands).


				N. Ward
				Estes and			All Other
	Postle Field			Ancillary			Acquisitions
Purchase Price:
Cash paid, net of cash acquired	$	343,000		$	442,000		$	95,433
Common stock issued		—			17,176			—

Total	$	343,000		$	459,176		$	95,433


Allocation of Purchase Price:
Working capital	$	—		$	—		$	2,096
Oil and gas properties		343,513			463,340			95,832
Other long-term assets		243			—			—
Other non-current liabilities		(756	)		(4,164	)		(2,495	)

Total	$	343,000		$	459,176		$	95,433

3.		DERIVATIVE FINANCIAL INSTRUMENTS

		Whiting enters into derivative contracts, primarily costless collars, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Costless collars are designed to establish floor and ceiling prices on anticipated future oil and gas production. The Company has designated these contracts as cash flow hedges designed to achieve a more predictable cash flow, as well as to reduce its exposure to price volatility. 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 instruments for speculative or trading purposes.

		All derivatives are recognized on the balance sheet and measured at fair value. Unrealized gains and losses on effective cash flow hedge derivatives are recorded as a component of accumulated other comprehensive income (loss). When the hedged transaction occurs, the realized gain or loss on the hedge derivative is transferred from accumulated other comprehensive income (loss) to earnings. Realized gains and losses on commodity hedge derivatives are recognized as “gain (loss) on oil and natural gas hedging activities”, and the ineffective portion of hedge derivatives, if any, is recorded as a derivative fair value gain or loss in the consolidated statements of income. Realized gains and losses on interest hedge derivatives are recorded as adjustments to interest expense. Derivative settlements are included in cash flows from operating activities.

		At June 30, 2006, accumulated other comprehensive loss consisted of $58.3 million ($35.8 million after tax) of unrealized losses, representing the mark-to-market value of the Company’s open commodity contracts, designated as cash flow hedges, as of the balance sheet date. For the three months ended June 30, 2006 and 2005, Whiting recognized a realized gain of $0.04 million and a realized loss of $4.9 million, respectively, on commodity derivative settlements. For the six months ended June 30, 2006 and 2005, Whiting recognized realized losses of $9.5 million and $6.9 million, respectively, on commodity derivative settlements.

		The Company has also entered into an interest rate swap designated as a fair value hedge as further explained in Long-Term Debt.

4.		LONG-TERM DEBT

		Long-term debt consisted of the following at June 30, 2006 and December 31, 2005 (in thousands):


	June 30,		December 31,
	2006		2005
Credit Agreement	$	310,000	$	260,000
7.25% Senior Subordinated Notes due 2012, net of unamortized debt discount of $766 and $848, respectively		145,873		148,014
7.25% Senior Subordinated Notes due 2013, net of unamortized debt discount of $2,665 and $2,916, respectively		217,335		217,084
7% Senior Subordinated Notes due 2014		250,000		250,000

Total debt	$	923,208	$	875,098

		*Credit Agreement*—The Company’s wholly-owned subsidiary, Whiting Oil and Gas Corporation, has a $1.2 billion credit agreement with a syndicate of banks that, as of June 30, 2006, had a borrowing base of $800.0 million. The borrowing base under the credit agreement is determined at the discretion of the lenders based on the collateral value of proved reserves that have been mortgaged to the lenders and is subject to regular redetermination on May 1 and November 1 of each year as well as special redeterminations described in the credit agreement. As of June 30, 2006, the outstanding principal balance under the credit agreement was $310.0 million.

		The credit agreement provides for interest only payments until August 31, 2010, when the entire amount borrowed is due. Whiting Oil and Gas Corporation may, throughout the term of the credit agreement, borrow, repay and reborrow up to the borrowing base in effect from time to time. The lenders under the credit agreement have also committed to issue letters of credit for the account of Whiting Oil and Gas Corporation or other designated subsidiaries of the Company from time to time in an aggregate amount not to exceed $50.0 million. As of June 30, 2006, letters of credit totaling $0.3 million were outstanding under the credit agreement.

		Interest accrues, at Whiting Oil and Gas Corporation’s option, at either (1) the base rate plus a margin where the base rate is defined as the higher of the federal funds rate plus 0.5% or the prime rate and the margin varies from 0% to 0.50% depending on the utilization percentage of the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.00% to 1.75% depending on the utilization percentage of the borrowing base. Whiting Oil and Gas Corporation has consistently chosen the LIBOR rate option since it delivers the lowest effective interest rate. Commitment fees of 0.25% to 0.375% accrue on the unused portion of the borrowing base, depending on the utilization percentage, and are included as a component of interest expense. At June 30, 2006, weighted average interest rate on the outstanding principal balance under the credit agreement was 6.2%.

		The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, change material agreements, incur liens and engage in certain other transactions without the prior consent of the lenders and requires the Company to maintain a debt to EBITDAX (as defined in the credit agreement) ratio of less than 3.5 to 1 and a working capital ratio (as defined in the credit agreement) of greater than 1 to 1. Except for limited exceptions, including the payment of interest on the senior notes, the credit agreement restricts the ability of Whiting Oil and Gas Corporation and Equity Oil Company to make any dividends, distributions, principal payments on senior notes, or other payments to the Company. The restrictions apply to all of the net assets of these subsidiaries. The Company was in compliance with its covenants under the credit agreement as of June 30, 2006. The credit agreement is secured by a first lien on all of Whiting Oil and Gas Corporation’s properties included in the borrowing base for the credit agreement. Whiting Petroleum Corporation and its wholly-owned subsidiary, Equity Oil Company, have guaranteed the obligations of Whiting Oil and Gas Corporation under the credit agreement. Whiting Petroleum Corporation has pledged the stock of Whiting Oil and Gas Corporation and Equity Oil Company as security for its guarantee and Equity Oil Company has mortgaged all of its properties included in the borrowing base for the credit agreement as security for its guarantee.

		*Senior Subordinated Notes* — In October 2005, the Company issued $250.0 million of 7% Senior Subordinated Notes due 2014 at par. The estimated fair value of these notes was $235.3 million as of June 30, 2006.

		In April 2005, the Company issued $220.0 million of 7.25% Senior Subordinated Notes due 2013. The notes were issued at 98.507% of par and the associated discount of $3.3 million is being amortized to interest expense over the term of the notes yielding an effective interest rate of 7.5%. The estimated fair value of these notes was $210.4 million as of June 30, 2006.

		In May 2004, the Company issued $150.0 million of its 7.25% Senior Subordinated Notes due 2012. The notes were issued at 99.26% of par and the associated discount of $1.1 million is being amortized to interest expense over the term of the notes yielding an effective interest rate of 7.4%. The estimated fair value of these notes was $143.4 million as of June 30, 2006.

		The notes are unsecured obligations of the Company and are subordinated to all of the Company’s senior debt. The indentures governing the notes contain various restrictive covenants that are substantially identical and may limit the Company’s and its subsidiaries’ ability to, among other things, pay cash dividends, redeem or repurchase the Company’s capital stock or the Company’s subordinated debt, make investments, incur additional indebtedness or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries taken as a whole, and enter into hedging contracts. These covenants may potentially limit the discretion of the Company’s management in certain respects. In addition, Whiting Oil and Gas Corporation’s

credit agreement restricts the ability of the Company’s subsidiaries to make certain payments, including principal on the notes, to the Company. The Company was in compliance with these covenants as of June 30, 2006. Three of the Company’s subsidiaries, Whiting Oil and Gas Corporation, Whiting Programs, Inc. and Equity Oil Company (the “Guarantors”), have fully, unconditionally, jointly and severally guaranteed the Company’s obligations under the notes. The Company does not have any subsidiaries other than the Guarantors, minor or otherwise, within the meaning of Rule 3-10(h)(6) of Regulation S-X of the Securities and Exchange Commission, and the Company has no independent assets or operations.

		*Interest Rate Swap—*In August 2004, the Company entered into an interest rate swap contract to hedge the fair value of $75.0 million of its 7.25% Senior Subordinated Notes due 2012, which increased the effective interest rate on those notes to 7.5% at June 30, 2006. Because this swap meets the conditions to qualify for the “short cut” method of assessing effectiveness under the provisions of Statement of Financial Accounting Standards No. 133, the change in fair value of the debt is assumed to equal the change in the fair value of the interest rate swap. As such, there is no ineffectiveness assumed to exist between the interest rate swap and the notes.

		The interest rate swap is a fixed for floating swap in that the Company receives the fixed rate of 7.25% and pays the floating rate. The floating rate is redetermined every six months based on the LIBOR rate in effect at the contractual reset date. When LIBOR plus the Company’s margin of 2.345% is less than 7.25%, the Company receives a payment from the counterparty equal to the difference in rate times $75.0 million for the six month period. When LIBOR plus the Company’s margin of 2.345% is greater than 7.25%, the Company pays the counterparty an amount equal to the difference in rate times $75.0 million for the six month period. As of June 30, 2006, the Company has recorded a long-term liability of $3.4 million related to the interest rate swap, which has been designated as a fair value hedge, with an offsetting reduction in the fair value of the 7.25% Senior Subordinated Notes due 2012.

5.		ASSET RETIREMENT OBLIGATIONS

		The Company’s asset retirement obligations primarily represent the estimated present value of amounts expected to be incurred to plug, abandon and remediate producing properties (including removal of certain onshore and offshore facilities in California) at the end of their productive lives, in accordance with applicable state and federal laws. The Company determines asset retirement obligations by calculating the present value of estimated cash flows related to plug and abandonment liabilities. The following is a summary of the asset retirement obligation activity for the six months ended June 30, 2006 (in thousands):


Asset retirement obligation, January 1, 2006	$	32,246
Additional liability incurred		470
Revisions in estimated cash flows		193
Accretion expense		1,120
Liabilities settled		(921	)

Asset retirement obligation, June 30, 2006	$	33,108

6.		STOCKHOLDERS’ EQUITY

		*Equity Incentive Plan—*The Company maintains the Whiting Petroleum Corporation 2003 Equity Incentive Plan, pursuant to which two million shares of the Company’s common stock have been reserved for issuance. In periods prior to January 1, 2006, the Company had granted 197,573 shares of restricted stock under this plan, of which 16,989 shares were forfeited and 6,122 shares were cancelled when used for employee tax withholdings. All restricted stock awards granted to date vest ratably over three years.

		The following table shows a summary of the Company’s nonvested restricted stock as of June 30, 2006 as well as activity during the six months then ended (share and per share data, not presented in thousands):


				Weighted
				Average
	Number			Grant Date
	of Shares			Fair Value

Restricted stock awards nonvested, January 1, 2006		145,763		$	32.34
Granted		125,999		$	43.38
Vested		(52,155	)	$	31.15
Forfeited		(8,170	)	$	37.37

Restricted stock awards nonvested, June 30, 2006		211,437		$	38.94

		The grant date fair value of restricted stock is determined based on the closing bid price of the Company’s common stock on the grant date. The Company uses historical data and projections to estimate expected employee behaviors related to restricted stock forfeitures. SFAS 123R requires that expected forfeitures be included as part of the grant date estimate of compensation cost. Prior to adopting SFAS 123R, the Company reduced share-based compensation expense for forfeitures only when they occurred.

		As of June 30, 2006, there was $5.1 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 2.2 years.

		*Rights Agreement—*On February 23, 2006, the Board of Directors of the Company declared a dividend of one preferred share purchase right (a “Right”) for each outstanding share of common stock of the Company. The dividend was paid on March 9, 2006 to the stockholders of record as of March 2, 2006. Each Right entitles the registered holder to purchase from the Company one one-hundredth of a share of Series A Junior Participating Preferred Stock, par value $0.001 par value (“Preferred Shares”), of the Company, at a price of $180.00 per one one-hundredth of a Preferred Share, subject to adjustment. If any person becomes a 15% or more stockholder of the Company, then each Right (subject to certain limitations) will entitle its holder to purchase, at the Right’s then current exercise price, a number of shares of common stock of the Company or of the acquirer having a market value at the time of twice the Right’s per share exercise price. The Company’s Board of Directors

may redeem the Rights for $.001 per Right at any time prior to the time when the Rights become exercisable. Unless the Rights are redeemed, exchanged or terminated earlier, they will expire on February 23, 2016.

7.		EQUITY BENEFIT PLANS

		*Production Participation Plan—*The Company has a Production Participation Plan (the “Plan”) for all employees. 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. 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 natural 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. Current accrued compensation expense under the Plan for the six months ended June 30, 2006 and 2005 amounted to $6.6 million and $4.3 million related to general and administrative expense and $1.2 million and $0.8 million related to exploration expense, respectively.

		The Company uses average historical prices to estimate the vested long-term Production Participation Plan liability. At June 30, 2006, the Company used five-year average historical NYMEX prices of $43.20 for crude oil and $5.80 for natural gas to estimate this liability. If the Company were to terminate the Plan or upon a change in control (as defined in the Plan), all employees fully vest and the Company would distribute to each Plan participant the fair market value of their respective interest in a lump sum payment twelve months after the date of termination or within one month after a change in control event. Based on prices at June 30, 2006, 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 $76.2 million. This amount includes $10.3 million attributable to proved undeveloped oil and gas properties. The ultimate sharing contribution for proved undeveloped oil and gas properties will be awarded in the year of Plan termination or change of control. The Company has no intention to terminate the Plan.

		The following table presents changes in the estimated long-term liability related to the Plan for the six months ended June 30, 2006 (in thousands):


Production Participation Plan liability, January 1, 2006	$	19,287
Change in liability for accretion, vesting and change in estimate		11,988
Reduction in liability for cash payments accrued and recognized as compensation expense		(7,844	)

Production Participation Plan liability, June 30, 2006	$	23,431

The Company records the expense associated with changes in the present value of estimated future payments under the Plan as a separate line item in the consolidated statements of income. The amount recorded is not allocated to general and administrative expense or

exploration expense because the adjustment of the liability is associated with the future net cash flows from oil and gas properties rather than current period performance. The table below presents the estimated allocation of the change in the liability if the Company did allocate the adjustment to these specific line items (in thousands):


	Six Months Ended June 30,
	2006		2005
General and administrative expense	$	3,481	$	230
Exploration expense		663		39

Total	$	4,144	$	269

8.		COMMITMENTS AND CONTINGENCIES

		*Non-cancelable Leases—*The Company leases 87,000 square feet of administrative office space in Denver, Colorado under an operating lease arrangement through October 31, 2010 and an additional 23,000 square feet of office space in Midland, Texas through February 28, 2008. Rental expense for the first six months of 2006 and 2005 was $1.0 million and $0.7 million, respectively. A summary of future minimum lease payments under its non-cancelable operating leases as of June 30, 2006 is as follows (in thousands):


2006	$	850
2007		1,682
2008		1,481
2009		1,469
2010		1,224

Total	$	6,706

		*Purchase Contract—*The Company has entered into two take-or-pay purchase agreements, one agreement in July 2005 for 9.5 years and one agreement in March 2006 for eight years, whereby the Company has committed to buy certain volumes of CO2 for a fixed fee, subject to annual escalation, for use in enhanced recovery projects in the Postle field in Texas County, Oklahoma and the North Ward Estes field in Ward County, Texas. The purchase agreements are with different suppliers. Under the terms of the agreements, the Company is obligated to purchase a minimum daily volume of CO2 or else pay for any deficiencies at the price in effect when delivery was to have occurred. The CO2 volumes planned for use on the enhanced recovery projects in the Postle and North Ward Estes fields currently exceed the minimum daily volumes provided in these take-or-pay purchase agreements. Therefore, the Company expects to avoid any payments for deficiencies. As of June 30, 2006, commitments under the purchase agreements amounted to $316.3 million through 2014.

		*Drilling Contracts—*The Company entered into three separate three-year agreements for rigs drilling in the U.S. Rocky Mountain region during 2005 and one agreement in February 2006 for a rig drilling in North Dakota. As of June 30, 2006, these agreements had total commitments of $27.3 million and early termination would require maximum penalties of $19.1 million. No other drilling rigs working for the Company are currently under long-term contracts or contracts which cannot be terminated at the end of the well that is currently being drilled.

		*Price-sharing Agreement —* The Company, as part of a 2002 purchase transaction, agreed to share with the seller 50% of the actual price received for certain crude oil production in excess of $19.00 per barrel. The agreement runs through December 31, 2009 and contains a 2% price escalation per year. As a result, the sharing amount at January 1, 2006 increased to 50% of the actual price received in excess of $20.56 per barrel. Approximately 39,600 net barrels of crude oil per month (less than 5% of June 2006 net crude oil production) are currently subject to this sharing agreement. The terms of the agreement do not provide for a maximum amount to be paid. The Company paid $4.4 million and $3.2 million for the six month periods ended June 30, 2006 and 2005, respectively, under this agreement.

		*Tax Separation and Indemnification Agreement with Alliant Energy —* Prior to Whiting’s initial public offering in November 2003, the Company was a wholly owned indirect subsidiary of Alliant Energy Corporation (“Alliant Energy”), a holding company whose primary businesses are utility companies. In connection with Whiting’s initial public offering, the Company entered into a tax separation and indemnification agreement with Alliant Energy. Pursuant to this agreement, the Company and Alliant Energy made a tax election with the effect that the tax bases of the assets of Whiting and its subsidiaries were increased to the deemed purchase price of their assets immediately prior to such initial public offering. Whiting has adjusted deferred taxes on its balance sheet to reflect the new tax bases of the Company’s assets. The additional bases are expected to result in increased future income tax deductions and, accordingly, may reduce income taxes otherwise payable by Whiting.

		Under this agreement, the Company has agreed to pay Alliant Energy 90% of the future tax benefits the Company realizes annually as a result of this step-up in tax basis for the years ending on or prior to December 31, 2013. Such tax benefits will generally be calculated by comparing the Company’s actual taxes to the taxes that would have been owed by the Company had the increase in bases not occurred. In 2014, Whiting will be obligated to pay Alliant Energy 90% of the present value of the remaining tax benefits assuming all such tax benefits will be realized in future years. Future tax benefits in total will approximate $64.6 million. The Company has estimated that total payments to Alliant Energy will approximate $49.2 million on an undiscounted basis, with a present value of $29.9 million.

		The Company monitors the estimate of when payments will be made and adjusts the accretion of this liability prospectively. During the first six months of 2006, the Company did not make any payments under this agreement but did recognize $1.1 million of accretion expense which is included as a component of interest expense. The Company’s estimated payment of $4.3 million to be made in 2006 under this agreement is reflected as a current liability at June 30, 2006.

		The Tax Separation Agreement provides that if tax rates were to change (increase or decrease), the tax benefit or detriment would result in a corresponding adjustment of the Tax Sharing liability. For purposes of this calculation, management has assumed that no such change will occur during the remaining term of this agreement.

Litigation—The Company is subject to litigation claims and governmental and regulatory controls arising in the ordinary course of business. It is the opinion of the Company’s management that all claims and litigation involving the Company are not likely to have a material adverse effect on its financial position, cash flows or results of operations.

9.		RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

		In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes. The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 is expected to have a minimal impact on the Company’s consolidated financial position, results of operations or cash flows.

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 operating subsidiaries, Whiting Oil and Gas Corporation and Equity Oil Company. When the context requires, we refer to these entities separately.

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. Some, but not all, of the risks and uncertainties include: declines in oil or gas prices; our level of success in exploitation, exploration, development and production activities; the timing of our exploration and development expenditures, including our ability to obtain drilling rigs; our ability to obtain external capital to finance acquisitions; our ability to identify and complete acquisitions and to successfully integrate acquired businesses, including our ability to realize cost savings from completed acquisitions; unforeseen underperformance of or liabilities associated with acquired properties; inaccuracies of our reserve estimates or our assumptions underlying them; 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; risks related to our level of indebtedness and periodic redeterminations of our borrowing base under our credit facility; our ability to replace our oil and gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry; 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 fiscal year ended December 31, 2005. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this report.

Overview

We are engaged in crude oil and natural gas exploitation, acquisition, exploration and production activities primarily in the Permian Basin, Rocky Mountains, Mid-Continent, Gulf Coast and Michigan regions of the United States. Over the last five years, we have emphasized the acquisition of properties that provided current production and significant upside potential through further development. Our drilling activity is directed at this development, specifically on projects that we believe provide repeatable successes in particular fields. Our combination of acquisitions and development allows us to direct our capital resources to what we believe to be the most advantageous investments.

We have historically acquired operated as well as non-operated properties that meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation 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 provided a foothold 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 are of the opinion that the sale 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 factors 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. Sustained periods of low prices for oil or gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and gas reserves that we can economically produce and our access to capital.

On June 1, 2006, we acquired the Postle field oil gathering system and oil transportation line extending 13 miles from the eastern side of the Postle field to a connection point with an interstate oil pipeline in Hooker, Oklahoma. We purchased the oil gathering system and pipeline for $5.3 million in cash.

We completed four separate acquisitions of producing properties during 2005. The combined purchase price for these four acquisitions was $897.7 million for total estimated proved reserves as of the effective dates of the acquisitions of approximately 133.7 MMBOE. Although independent engineers estimated probable and possible reserves relating to certain 2005 acquisitions, we, consistent with our present acquisition practices, have associated all acquisition costs with proved reserves. Because of our substantial recent acquisition activity, our discussion and analysis of our historical financial condition and results of operations for the periods discussed below may not necessarily be comparable with or applicable to our future results of operations. Our historical results include the results from our recent acquisitions beginning on the following dates: North Ward Estes and Ancillary Properties, October 4, 2005; Postle Properties, August 4, 2005; Limited Partnership Interests, June 23, 2005; and Green River Basin, March 31, 2005.

Results of Operations

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Selected Operating Data:


	Six Months Ended
	June 30,
	2006			2005
Net production:
Oil (MMbls)		4.81			2.95
Natural gas (Bcf)		15.96			14.98

Total production (MMBOE)		7.47			5.45

Oil and natural gas sales (in millions):
Oil(1)	$	279.8		$	135.9
Natural gas(1)		113.7			85.5

Total oil and natural gas sales	$	393.5		$	221.4

Average sales prices:
Oil (per Bbl)	$	58.16		$	46.03
Effect of oil hedges on average price (per Bbl)		(1.86	)		(2.35	)

Oil net of hedging (per Bbl)	$	56.30		$	43.68

Average NYMEX price	$	67.14		$	51.53

Natural gas (per Mcf)	$	7.13		$	5.71
Effect of natural gas hedges on average price (per Mcf)		(0.03	)		—

Natural gas net of hedging (per Mcf)	$	7.10		$	5.71

Average NYMEX price	$	7.91		$	6.51

Cost and expense (per BOE):
Lease operating expenses	$	11.92		$	7.88
Production taxes	$	3.26		$	2.65
Depreciation, depletion and amortization expense	$	9.94		$	7.54
General and administrative expenses	$	2.58		$	2.44


(1)		Before consideration of hedging transactions.

Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased $172.1 million to $393.5 million in the first six months of 2006 compared to the first six months of 2005. Sales are a function of sales volumes and average sales prices. Our oil sales volumes increased 63% and our natural gas sales volumes increased 7% between periods. The volume increases resulted from acquisitions completed in 2005 and successful drilling activities over the past year that produced new sales volumes that more than offset natural production decline. Our average price for crude oil increased 26% and our average price for natural gas sales increased 25% between periods.

Gain (Loss) on Oil and Natural Gas Hedging Activities. We hedged 54% of our oil volumes during the first six months of 2006 incurring a hedging loss of $9.0 million, and 60% of our oil volumes during the first six months of 2005 incurring a loss of $6.9 million. We hedged 58% of our natural gas volumes during the first six months of 2006, incurring a hedging loss of $0.5 million, and 60% of our natural gas volumes during the first six months of 2005, incurring no hedging loss or gain. See Item 3, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil and natural gas hedges as of July 17, 2006.

Lease Operating Expenses. Our lease operating expenses increased $46.1 million to $89.1 million in the first six months of 2006 compared to the first six months of 2005. The increase resulted primarily from costs associated with new property acquisitions during 2005. Our lease operating expense as a percentage of oil and gas sales increased from 19% during the first six months of 2005 to 23% during the first six months of 2006. Our lease operating expenses per BOE increased from $7.88 during the first six months of 2005 to $11.92 during the first six months of 2006. The increase of 51% on a BOE basis was primarily caused by higher energy costs and increases in the cost of oil field goods and services due to higher demand in the industry. Approximately 40% of our lease operating expenses directly or indirectly relate to energy prices. We also incurred a high level of workover activity on recently acquired properties during the first six months of 2006 which amounted to $4.1 million, as compared to $1.6 million of workover activity during the first six months of 2005.

Production Taxes. The production taxes we pay are generally calculated as a percentage of oil and gas sales revenue before the effects of hedging. We take full advantage of all credits and exemptions allowed in the various taxing jurisdictions. Our production taxes for the first six months of 2006 and 2005 were 6.2% and 6.5%, respectively, of oil and gas sales.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $33.1 million to $74.2 million during the first six months of 2006 as compared to the first six months of 2005. The increase resulted from higher production volumes and capitalized costs in 2006 and an increase in our DD&A rate. On a BOE basis, the rate increased from $7.54 during the first six months of 2005 to $9.94 in the first six months of 2006. The primary factors causing the DD&A rate increase were higher costs of adding proved developed reserves during the latter half of 2005 and first six months of 2006, downward net reserve revisions at the end of 2005, and an increase in drilling expenditures, as costs to develop proved undeveloped reserves are not considered for DD&A purposes until incurred. Also contributing to our higher DD&A rate is the fact that we have associated all 2005 property acquisition costs with proved reserves, thereby including all such costs in our DD&A rate immediately when incurred. The components of our DD&A expense were as follows (in thousands):


	Six Months Ended June 30,
	2006		2005
Depletion and amortization	$	71,959	$	39,408
Depreciation		1,130		560
Accretion of asset retirement obligations		1,120		1,114

Total	$	74,209	$	41,082

Exploration and Impairment Costs. Our exploration and impairment costs increased $8.9 million to $16.3 million in the first six months of 2006 compared to the first six months of 2005. The components of exploration and impairment costs are as follows (in thousands):


	Six Months Ended June 30,
	2006		2005
Exploration	$	15,543	$	5,429
Impairment		713		1,928

Total	$	16,256	$	7,357

Higher exploratory costs resulted from two exploratory dry holes drilled in the Rocky Mountains region and one exploratory dry hole drilled in the Gulf Coast region, totaling $5.2 million for the first six months of 2006. In the first six months of 2005, we drilled a total of three exploratory dry holes, one each in the Permian, Rocky Mountains and Gulf Coast regions, totaling $1.8 million. We also hired additional geological and geophysical personnel to support the increased drilling budget from $223.6 million incurred in 2005 to a range of $400.0 million to $420.0 million in 2006. The impairment charge in 2006 related to amortized leasehold costs associated with individually insignificant unproved properties. The impairment charge in 2005 related to unrecoverable costs associated with our investment in the Cherokee Basin of Kansas.

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


	Six Months Ended June 30,
	2006			2005
General and administrative expenses	$	29,068		$	18,417
Reimbursements		(9,819	)		(5,144	)

General and administrative expense, net	$	19,249		$	13,273

General and administrative expense before reimbursements increased $10.7 million to $29.1 million during the first six months of 2006. The largest components of the increase related to higher costs for personnel salaries, benefits and related taxes of $7.1 million and an increase in the current year accrual for cash payments under our Production Participation Plan of $2.3 million. Personnel salary expenses were higher in 2006 due to an increase in our employee base resulting from our continued growth. The increased cost of the Production Participation Plan was caused primarily by higher 2006 production volumes and higher average sales prices between periods. The increase in reimbursements was caused by a higher number of operated properties due to recent acquisitions and drilling activities during the latter half of 2005 and first six months of 2006. Our net general and administrative expenses on a BOE basis increased 6% between periods from $2.44 to $2.58. As a percentage of oil and gas sales, our general and administrative expenses decreased from 6% during the first six months of 2005 to 5% during the first six months of 2006, as general and administrative costs increased at a slower rate than the increases in our oil and gas volumes and sales prices.

Change in Production Participation Plan Liability. For the six months ended June 30, 2006, this non-cash expense increased $3.9 million. This expense represents the change in the vested present value of estimated future payments to be made to participants after 2007 under our Production Participation Plan. Although payments take place over the life of oil and gas properties contributed to the Plan, some properties for over 20 years, we must expense the present value of estimated future payments over the Plan’s five year vesting period. The increase in expense

primarily reflects changes to future cash flow estimates due to the effect of a sustained higher price environment and recent acquisitions, as well as employees’ continued vesting in the Plan. Assumptions that are used to calculate this liability are subject to estimation and will vary from period to period based on the current market for oil and gas prices, discount rates and overall market conditions.

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


	Six Months Ended June 30,
	2006			2005
Credit Agreement	$	9,510		$	2,433
Senior Subordinated Notes		22,172			7,933
Amortization of debt issue costs and debt discount		2,632			1,697
Accretion of tax sharing liability		1,050			1,240
Other		443			75
Capitalized interest		(206	)		—

Total interest expense	$	35,601		$	13,378

The increase in interest expense was mainly due to the April 2005 issuance of $220.0 million of 7.25% Senior Subordinated Notes due 2013, the October 2005 issuance of $250.0 million of 7% Senior Subordinated Notes due 2014 and additional borrowings outstanding under our credit agreement. The higher amortization of debt issue costs and debt discount from the end of second quarter of 2005 to the end of the second quarter of 2006 relates to additional debt issue costs associated with the April 2005 and October 2005 issuances of Senior Subordinated Notes, and the amendment to the credit facility.

Our weighted average debt outstanding in the first six months of 2006 was $924.8 million versus $347.0 million in the first six months of 2005. Our weighted average effective cash interest rate was 6.9% in the first six months of 2006 versus 6.0% in the first six months of 2005. After inclusion of non-cash interest costs related to the amortization of debt issue costs and debt discount and the accretion of the tax sharing liability, our weighted average effective all-in interest rate was 7.5% in the first six months of 2006 versus 7.1% in the first six months of 2005.

Income Tax Expense. Income tax expense totaled $42.9 million for the first six months of 2006 and $31.6 million for the first six months of 2005. Our effective income tax rate decreased from 38.6% for the first six months of 2005 to 35.3% for the first six months of 2006 due to the recognition of a $2.5 million deferred tax benefit for 2005 enhanced oil recovery (“EOR”) tax credits and a deferred tax benefit of $0.7 million as a result of recent Texas corporate tax legislation and other one-time items. On May 18, 2006, a Texas law was enacted which changes the existing Texas franchise tax from a tax based on net income or taxable capital to a new tax based on gross margin (“Margin Tax”). The effective date of the new legislation is January 1, 2008, which means that the Company will file its first Margin Tax return on May 15, 2008 based on 2007 income.

EOR credits are a credit against federal income taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed “enhanced” tertiary recovery methods. Federal EOR credits are subject to phase-out according to the level of average domestic crude prices. Due to recent high oil prices, we will not be earning any federal EOR credits during 2006.

The current portion of income tax expense was $4.6 million for the six months ended June 30, 2006 compared to $4.7 million in the same period in 2005. These amounts were 11% and 15%, respectively, of total income tax expense for the six months ended June 30, 2006 and 2005 primarily due to intangible drilling deductions allowed within our drilling capital expenditures.

Net Income. Net income increased from $50.3 million during the first six months of 2005 to $78.9 million during the first six months of 2006. The primary reasons for this increase included a 37% increase in equivalent volumes sold and 28% higher oil and gas prices net of hedging between periods, which were partially offset by higher lease operating expense, production taxes, DD&A, exploration and impairment, general and administrative, Production Participation Plan, interest expenses, and income taxes resulting from our continued growth.

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005

Selected Operating Data:


	Three Months Ended
	June 30,
	2006		2005
Net production:
Oil (MMbls)		2.44		1.49
Natural gas (Bcf)		8.16		7.45

Total production (MMBOE)		3.80		2.73

Oil and natural gas sales (in millions):
Oil(1)	$	149.3	$	71.0
Natural gas(1)		54.3		45.0

Total oil and natural gas sales	$	203.6	$	116.0

Average sales prices:
Oil (per Bbl)	$	61.22	$	47.68
Effect of oil hedges on average price (per Bbl)		—		(3.28	)

Oil net of hedging (per Bbl)	$	61.22	$	44.40

Average NYMEX price	$	70.70	$	53.13

Natural gas (per Mcf)	$	6.66	$	6.04
Effect of natural gas hedges on average price (per Mcf)		—		—

Natural gas net of hedging (per Mcf)	$	6.66	$	6.04

Average NYMEX price	$	6.80	$	6.74

Cost and expense (per BOE):
Lease operating expenses	$	11.76	$	8.10
Production taxes	$	3.26	$	2.90
Depreciation, depletion and amortization expense	$	10.24	$	7.60
General and administrative expenses	$	2.54	$	2.61


(1)		Before consideration of hedging transactions.

Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased $87.7 million to $203.6 million in the second quarter of 2006 compared to the second quarter of 2005. Sales are a function of sales volumes and average sales prices. Our oil sales volumes increased 64% and our natural gas sales volumes increased 10% between periods. The volume increases resulted

from acquisitions completed in 2005 and successful drilling activities over the past year that produced new sales volumes that more than offset natural production decline. Our average price for crude oil increased 28% and our average price for natural gas sales increased 10% between periods.

Gain (Loss) on Oil and Natural Gas Hedging Activities. We hedged 55% of our oil volumes during the second quarter of 2006 incurring no hedging loss or gain, and 50% of our oil volumes during the second quarter of 2005 incurring a hedging loss of $4.9 million. We hedged 59% of our natural gas volumes during the second quarter of 2006, incurring a hedging gain of $0.04 million, and 60% of our natural gas volumes during the second quarter of 2005, incurring no hedging loss or gain. See Item 3, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil and natural gas hedges as of July 17, 2006.

Lease Operating Expenses. Our lease operating expenses increased $22.5 million to $44.7 million in the second quarter of 2006 compared to the second quarter of 2005. The increase resulted primarily from costs associated with new property acquisitions during 2005. Our lease operating expense as a percentage of oil and natural gas sales increased from 19% during the second quarter of 2005 to 22% during the second quarter of 2006. Our lease operating expenses per BOE increased from $8.10 during the second quarter of 2005 to $11.76 during the second quarter of 2006. The increase of 45% on a BOE basis was primarily caused by higher energy costs and increases in the cost of oil field goods and services due to higher demand in the industry. Approximately 40% of our lease operating expenses directly or indirectly relate to energy prices. We also incurred a high level of workover activity on recently acquired properties during the second quarter of 2006 which amounted to $1.8 million, as compared to $1.2 million of workover activity during the second quarter of 2005.

Production Taxes. The production taxes we pay are generally calculated as a percentage of oil and natural gas sales revenue before the effects of hedging. We take full advantage of all credits and exemptions allowed in the various taxing jurisdictions. Our production taxes for the second quarter of 2006 and 2005 were 6.1% and 6.8%, respectively, of oil and natural gas sales.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $18.2 million to $38.9 million during the second quarter of 2006 as compared to the second quarter of 2005. The increase resulted from higher production volumes and capitalized costs in 2006 and an increase in our DD&A rate. On a BOE basis, the rate increased from $7.60 during the second quarter of 2005 to $10.24 in the second quarter of 2006. The primary factors causing the DD&A rate increase were higher costs of adding proved developed reserves during the latter half of 2005 and first half of 2006, downward net reserve revisions at the end of 2005, and an increase in drilling expenditures, as costs to develop proved undeveloped reserves are not considered for DD&A purposes until incurred. Also contributing to our higher DD&A rate is the fact that we have associated all 2005 property acquisition costs with proved reserves, thereby including all such costs in our DD&A rate immediately when incurred. The components of our DD&A expense were as follows (in thousands):


	Three Months Ended June 30,
	2006		2005
Depletion and amortization	$	37,738	$	19,889
Depreciation		599		290
Accretion of asset retirement obligations		572		556

Total	$	38,909	$	20,735

Exploration and Impairment Costs. Our exploration and impairment costs increased $3.2 million to $9.2 million in the second quarter of 2006 compared to the second quarter of 2005. The components of exploration and impairment costs are as follows (in thousands):


	Three Months Ended June 30,
	2006		2005
Exploration	$	8,642	$	4,130
Impairment		572		1,928

Total	$	9,214	$	6,058

Higher exploratory costs resulted from two exploratory dry holes drilled in the Rocky Mountains region during the second quarter of 2006 totaling $2.4 million. In the second quarter of 2005, we drilled a total of two exploratory dry holes, one each in the Permian and Gulf Coast regions, totaling $1.7 million. We also hired additional geological and geophysical personnel to support the increased drilling budget from $223.6 million incurred in 2005 to a range of $400.0 million to $420.0 million in 2006. The impairment charge in 2006 related to amortized leasehold costs associated with individually insignificant unproved properties. The impairment charge in 2005 related to unrecoverable costs associated with our investment in the Cherokee Basin of Kansas.

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


	Three Months Ended June 30,
	2006			2005
General and administrative expenses	$	14,948		$	9,748
Reimbursements		(5,310	)		(2,617	)

General and administrative expense, net	$	9,638		$	7,131

General and administrative expense before reimbursements increased $5.2 million to $14.9 million during the second quarter of 2006. The largest components of the increase related to higher costs for personnel salaries, benefits and related taxes of $3.6 million and an increase in the current year accrual for cash payments under our Production Participation Plan of $1.4 million. Personnel salary expenses were higher in 2006 due to an increase in our employee base resulting from our continued growth. The increased cost of the Production Participation Plan was caused primarily by higher 2006 production volumes and higher average sales prices between periods. The increase in reimbursements was caused by a higher number of operated properties due to recent

acquisitions and drilling activities during the latter half of 2005 and first half of 2006. Our net general and administrative expenses on a BOE basis decreased 3% between periods from $2.61 to $2.54. As a percentage of oil and natural gas sales, our net general and administrative expenses decreased from 6% during the second quarter of 2005 to 5% during the second quarter of 2006, as general and administrative costs increased at a slower rate than the increases in our oil and gas volumes and sales prices.

Change in Production Participation Plan Liability. For the second quarter, this non-cash expense increased $2.5 million. This expense represents the change in the vested present value of estimated future payments to be made to participants after 2007 under our Production Participation Plan. Although payments take place over the life of oil and gas properties contributed to the Plan, some properties for over 20 years, we must expense the present value of estimated future payments over the Plan’s five year vesting period. The increase in expense primarily reflects changes to future cash flow estimates due to the effect of a sustained higher price environment and recent acquisitions, as well as employees’ continued vesting in the Plan. Assumptions that are used to calculate this liability are subject to estimation and will vary from period to period based on the current market for oil and natural gas prices, discount rates and overall market conditions.

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


	Three Months Ended June 30,
	2006			2005
Credit Agreement	$	5,393		$	616
Senior Subordinated Notes		11,163			5,834
Amortization of debt issue costs and debt discount		1,309			1,015
Accretion of tax sharing liability		525			620
Other		443			37
Capitalized interest		(206	)		—

Total interest expense	$	18,627		$	8,122

The increase in interest expense was mainly due to the October 2005 issuance of $250.0 million of 7% Senior Subordinated Notes due 2014 and additional borrowings outstanding under our credit agreement.

Our weighted average debt outstanding during the second quarter of 2006 was $947.5 million versus $372.0 million in the second quarter of 2005. Our weighted average effective cash interest rate was 7.1% during the second quarter of 2006 versus 7.0% during the second quarter of 2005. After inclusion of non-cash interest costs related to the amortization of debt issue costs and debt discount and the accretion of the tax sharing liability, our weighted average effective all-in interest rate was 7.6% during the second quarter of 2006 versus 8.0% during the second quarter of 2005.

Income Tax Expense. Income tax expense totaled $22.6 million for the second quarter of 2006 and $15.2 million for the second quarter of 2005. Our effective income tax rate decreased from 38.6% for the second quarter of 2005 to 33.0% for the second quarter of 2006 due to the recognition of a $2.5 million deferred tax benefit for 2005 enhanced oil recovery (“EOR”) tax credits and a deferred tax benefit of $0.7 million as a result of recent Texas corporate tax

legislation and other one-time items. On May 18, 2006, a Texas law was enacted which changes the existing Texas franchise tax from a tax based on net income or taxable capital to a new tax based on gross margin (“Margin Tax”). The effective date of the new legislation is January 1, 2008, which means that the Company will file its first Margin Tax return on May 15, 2008 based on 2007 income.

The current portion of income tax expense was $2.6 million for the quarter ended June 30, 2006 compared to $3.1 million in the same period in 2005. These amounts were 11% and 20%, respectively, of total income tax expense for both periods primarily due to intangible drilling deductions allowed within our drilling capital expenditures.

Net Income. Net income increased from $24.2 million during the second quarter of 2005 to $45.9 million during the second quarter of 2006. The primary reasons for this increase included a 39% increase in equivalent volumes sold and 35% higher oil and gas prices net of hedging between periods, which were partially offset by higher lease operating expense, production taxes, DD&A, exploration and impairment, general and administrative, Production Participation Plan, interest expenses, and income taxes resulting from our continued growth.

Liquidity and Capital Resources

Overview. At December 31, 2005, our debt to total capitalization ratio was 46.4%, we had $10.4 million of cash on hand and $997.9 million of stockholders’ equity. At June 30, 2006, our debt to total capitalization ratio was 45.8%, we had $12.1 million of cash on hand and $1,077.2 million of stockholders’ equity. In the first half of 2006, we generated an additional $224.8 million from operating activities, an increase of $85.0 million over the same period in 2005. Cash provided by operating activities increased primarily because of higher production from our recent acquisitions, successful drilling activities and higher average sales prices, and was reduced by higher operating costs. We also generated $49.8 million from financing activities primarily consisting of $50.0 million in net borrowings against our credit facility. Cash on hand and cash flows from operating and financing activities were primarily used to finance $234.4 million of drilling capital expenditures incurred in the first six months, $35.1 million in interest payments, $12.1 million in payments under the Production Participation Plan and $33.7 million of cash acquisition capital expenditures to acquire tubulars, unproved property leaseholds and the pipeline in the Postle field. The chart below details our drilling capital expenditures incurred by region during the first six months of 2006 (in thousands):


	Drilling Capex		% of Total
Permian Basin	$	100,104		43	%
Rocky Mountains		61,049		26	%
Mid-Continent		41,937		18	%
Gulf Coast		26,895		11	%
Michigan		4,376		2	%


Total Drilling Capex	$	234,361		100	%

We continually evaluate our capital needs and compare them to our capital resources. Our 2006 budgeted capital expenditures for the further development of our property base ranges from $400.0 million to $420.0 million, an increase from the $223.6 million incurred on capitalized development during 2005. Although we have no specific budget for property acquisitions in 2006, we will continue to seek property acquisition opportunities that complement our existing core property base. We expect to fund our additional 2006 development expenditures from internally generated cash flow and cash on hand. We believe that should attractive acquisition opportunities arise or development expenditures exceed $420.0 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 equity or agreements with industry partners. Our level of capital 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.

Credit Agreement. Whiting Oil and Gas Corporation has a $1.2 billion credit agreement with a syndicate of banks that, as of June 30, 2006, had a borrowing base of $800.0 million with $310.0 million outstanding leaving $490.0 million of available borrowing capacity.

The credit agreement provides for interest only payments until August 31, 2010, when the entire amount borrowed is due. Whiting Oil and Gas Corporation may, throughout the term of the credit agreement, borrow, repay and re-borrow up to the borrowing base in effect from time to time. The lenders under the credit agreement have also committed to issue letters of credit for the account of Whiting Oil and Gas Corporation or other designated subsidiaries of ours from time to time in an aggregate amount not to exceed $50.0 million. As of June 30, 2006, letters of credit totaling $0.3 million were outstanding under the credit agreement.

Interest accrues, at Whiting Oil and Gas Corporation’s option, at either (1) the base rate plus a margin where the base rate is defined as the higher of the prime rate or the federal funds rate plus 0.5% and the margin varies from 0% to 0.5% depending on the utilization percentage of the borrowing base, or (2) at the LIBOR rate plus a margin where the margin varies from 1.00% to 1.75% depending on the utilization percentage of the borrowing base. Whiting Oil and Gas Corporation has consistently chosen the LIBOR rate option since it delivers the lowest effective interest rate. Commitment fees of 0.25% to 0.375% accrue on the unused portion of the borrowing base, depending on the utilization percentage and are included as a component of interest expense. As of June 30, 2006, the effective weighted average interest rate on the entire outstanding principal balance under the credit agreement was 6.2%.

The credit agreement contains restrictive covenants that may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, change material agreements, incur liens and engage in certain other transactions without the prior consent of the lenders and requires us to maintain a debt to EBITDAX (as defined in the credit agreement) ratio of less than 3.5 to 1 and a working capital ratio (as defined in the credit agreement) of greater than 1 to 1. Except for limited exceptions, including the payment of interest on the senior notes, the credit agreement restricts the ability of Whiting Oil and Gas Corporation and Equity Oil Company to make any dividends, distributions or other payments to us. The restrictions apply to all of the net

assets of these subsidiaries. We were in compliance with our covenants under the credit agreement as of June 30, 2006. The credit agreement is secured by a first lien on all of Whiting Oil and Gas Corporation’s properties included in the borrowing base for the credit agreement. We and our wholly-owned subsidiary, Equity Oil Company, have guaranteed the obligations of Whiting Oil and Gas Corporation under the credit agreement. We have pledged the stock of Whiting Oil and Gas Corporation and Equity Oil Company as security for our guarantee, and Equity Oil Company has mortgaged all of its properties included in the borrowing base for the credit agreement as security for its guarantee.

Senior Subordinated Notes. In October 2005, we issued $250.0 million of 7% Senior Subordinated Notes due 2014 at par.

In April 2005, we issued $220.0 million of 7.25% Senior Subordinated Notes due 2013. The notes were issued at 98.507% of par and the associated discount is being amortized to interest expense over the term of the notes.

In May 2004, we issued $150.0 million of 7.25% Senior Subordinated Notes due 2012. The notes were issued at 99.26% of par and the associated discount is being amortized to interest expense over the term of the notes.

The notes are unsecured obligations of ours and are subordinated to all of our senior debt. The indentures governing the notes contain restrictive covenants that may limit our and our subsidiaries’ ability to, among other things, pay cash dividends, redeem or repurchase our capital stock or our subordinated debt, make investments, incur additional indebtedness 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. In addition, Whiting Oil and Gas Corporation’s credit agreement restricts the ability of our subsidiaries to make certain payments, including principal on the notes, to us. We were in compliance with these covenants as of June 30, 2006. Three of our subsidiaries, Whiting Oil and Gas Corporation, Whiting Programs, Inc. and Equity Oil Company, have fully, unconditionally, jointly and severally guaranteed our obligations under the notes.

Shelf Registration Statement. On May 8, 2006, we filed a universal shelf registration statement with the Securities and Exchange Commission to allow us to offer an indeterminate amount of securities in the future. The registration statement replaced our previous universal shelf registration statement, under which approximately $48.0 million of securities remained available for offering. Under the registration statement, we may periodically offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

Tax Separation and Indemnification Agreement with Alliant Energy. In connection with our initial public offering in November 2003, we entered into a tax separation and indemnification agreement with Alliant Energy, our former parent company. Pursuant to this agreement, we and Alliant Energy made a tax election with the effect that the tax bases of the assets of Whiting Oil and Gas Corporation and its subsidiaries were increased to the deemed purchase

price of their assets immediately prior to such initial public offering. We have adjusted deferred taxes on our balance sheet to reflect the new tax bases of our assets. The additional 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. Such tax benefits will generally be calculated by comparing our actual taxes to the taxes that would have been owed by us had the increase in bases not occurred. In 2014, we will be obligated to pay Alliant Energy 90% of the present value of the remaining tax benefits assuming all such tax benefits will be realized in future years. During 2005, we made a payment of $5.1 million under this agreement. During the first six months of 2006, we did not make any payments under this agreement but did recognize $1.1 million of accretion expense, which is included as a component of interest expense. Our estimate of payments to be made under this agreement of $4.3 million in 2006 was reflected as a current liability at June 30, 2006.

Schedule of Contractual Obligations. The following table summarizes our obligations and commitments as of June 30, 2006 to make future payments under certain contracts, aggregated by category of contractual obligation, for specified time periods. This table does not include asset retirement obligations or Production Participation Plan liabilities since we cannot determine with accuracy the timing of future payments. This table also does not include interest expense under Whiting Oil and Gas Corporation’s credit agreement since this is a floating rate instrument and we cannot determine with accuracy the timing of future loan advances and repayments or interest rates.


	Payments due by period
			Less than 1						More than 5
Contractual Obligations	Total		year		2-3 years		4-5 years		years
Long-term debt (a)	$	923,208	$	—	$	—	$	310,000	$	613,208
Cash interest expense on notes (b)		308,565		44,613		89,226		89,226		85,500
Purchase obligations (c)		316,325		15,102		74,124		102,883		124,216
Drilling rig contracts (d)		27,299		16,311		10,988		—		—
Derivative contract liability fair value (e)		58,260		28,845		29,415		—		—
Operating leases (f)		6,706		1,704		3,044		1,958		—
Tax separation and indemnification agreement with Alliant Energy (g)		29,880		4,254		7,056		5,734		12,836

Total	$	1,670,243	$	110,829	$	213,853	$	509,801	$	835,760


(a)		Long-term debt consists of the 7.25% Senior Subordinated Notes due 2012 and 2013, the 7% Senior Subordinated Notes due 2014 and the outstanding debt under our credit agreement, and assumes no principal repayment until the due date of the instruments.

(b)		Cash interest expense on the 7.25% Senior Subordinated Notes due 2012 and 2013 and the 7% Senior Subordinated Notes due 2014 is estimated assuming no principal repayment until the due date of the instruments. The interest rate swap on the $75.0 million of our $150.0 million fixed rate 7.25% Senior Subordinated Notes due 2012 is assumed to equal 7.6% until the due date of the instrument.

(c)		We entered into two take-or-pay purchase agreements, one agreement in July 2005 for 9.5 years and one agreement in March 2006 for eight years, whereby we have committed to buy certain volumes of CO2 for a fixed fee, subject to annual escalation, for use in enhanced recovery projects in our Postle field in Texas County, Oklahoma and our North Ward Estes field in Ward County, Texas. The purchase agreements are with different suppliers. Under the terms of the agreements, we are obligated to purchase a minimum daily volume of CO2 or else pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. As calculated on an annual basis, Whiting’s failure to purchase the minimum CO2 volumes requires us to pay the suppliers for any deficiency. The CO2 volumes planned for use on the enhanced recovery projects in the Postle and North Ward Estes fields currently exceed the minimum daily volumes provided in these take-or-pay purchase agreements. Therefore, we expect to avoid any payments for deficiencies.


(d)		We entered into three separate agreements for three rigs drilling in the U.S. Rocky Mountain region during 2005 and one agreement in February 2006 for a rig drilling in North Dakota. The 2005 contracts each have a term of three years and the 2006 contract has a two year term. As of June 30, 2006, early termination of these contracts would have required maximum penalties of $19.1 million. No other drilling rigs working for us are currently under long-term contracts or contracts which cannot be terminated at the end of the well that is currently being drilled. Due to their short-term nature and the indeterminate nature of the drilling time remaining on rigs drilling on a well-by-well basis, such obligations have not been included in this table.

(e)		We have entered into derivative contracts, primarily costless collars, to hedge our exposure to oil and gas price fluctuations. As of June 30, 2006, the forward price curves for oil and gas generally exceeded the price curves that were in effect when these contracts were entered into, resulting in a derivative fair value current liability of $28.8 million and long-term liability of $29.4 million. 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. See “Critical Accounting Policies and Estimates-Hedging” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2005 and Item 3, “Quantitative and Qualitative Disclosures About Market Risk” in this Quarterly Report on Form 10-Q for additional information regarding our derivative obligations.

(f)		We lease 87,000 square feet of administrative office space in Denver, Colorado under an operating lease arrangement through October 31, 2010 and an additional 23,000 square feet of office space in Midland, Texas through February 28, 2008.

(g)		Amounts shown are estimates based on estimated future income tax benefits from the increase in tax bases described under “Tax Separation and Indemnification Agreement with Alliant Energy” above.

Price-sharing Arrangement. As part of a 2002 purchase transaction, we agreed to share with the seller 50% of the actual price received for certain crude oil production in excess of $19.00 per barrel. The agreement runs through December 31, 2009 and contains a 2% price escalation per year. As a result, the sharing amount at January 1, 2006 increased to 50% of the actual price received in excess of $20.56 per barrel. As of June 30, 2006, approximately 39,600 net barrels of crude oil per month (less than 5% of June 2006 net crude oil production) are subject to this sharing agreement. The terms of the agreement do not provide for a maximum amount to be paid. During the first six months of 2006, we paid $4.4 million under this agreement. As of June 30, 2006, we have accrued an additional $0.9 million as currently payable.

New Accounting Policies

In December 2004, the Financial Accounting Standards Board issued SFAS No. 123(R), Share-Based Payment (“SFAS 123R”). This Statement is a revision of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), and supersedes Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”), and its related implementation guidance. SFAS 123R requires a company to measure the grant date fair value of equity awards given to employees in exchange for services and recognize that cost, less estimated forfeitures, over the period that such services are performed. Prior to adopting SFAS 123R, the Company accounted for stock-based compensation under SFAS 123, whereby the Company’s policy was to recognize actual forfeitures of restricted stock only when they occurred rather than estimate them at the grant date and subsequently true-up estimated forfeitures to actuals. SFAS 123R requires companies to include forfeitures as part of the grant date estimate of compensation cost. We adopted SFAS 123R on January 1, 2006 using the modified prospective transition method. In accordance with the modified prospective method, prior period results have not been restated.

The adoption of SFAS 123R had a minimal impact on income before income taxes and net income, and had no effect on basic or diluted earnings per share, for the three and six months ended June 30, 2006, as presented in the our consolidated statements of income.

New Accounting Pronouncements

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes. The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 is expected to have a minimal impact on our consolidated financial position, results of operations or cash flows.

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, 2005.

Effects of Inflation and Pricing

We experienced increased costs during 2005 and the first six months of 2006 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 gas increase, so do all associated costs. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans 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, continued high prices for oil and gas could result in increases in the costs of materials, services and personnel.

Item 3. Quantitative and Qualitative Disclosures about Market 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, 2005 and have not materially changed since that report was filed.

Our outstanding hedges as of July 17, 2006 are summarized below:

Monthly

Volume

NYMEX

Commodity

Period

(MMBtu)/(Bbl)

Floor/Ceiling

Crude Oil

07/2006 to 09/2006

125,000

45.00/$81.90

Crude Oil

07/2006 to 09/2006

215,000

50.00/$72.90

Crude Oil

07/2006 to 09/2006

110,000

50.00/$75.25

Crude Oil

10/2006 to 12/2006

125,000

45.00/$81.10

Crude Oil

10/2006 to 12/2006

215,000

50.00/$72.05

Crude Oil

10/2006 to 12/2006

110,000

50.00/$74.30

Crude Oil

01/2007 to 03/2007

125,000

45.00/$81.00

Crude Oil

01/2007 to 03/2007

215,000

50.00/$70.90

Crude Oil

01/2007 to 03/2007

110,000

50.00/$73.15

Crude Oil

04/2007 to 06/2007

110,000

50.00/$72.00

Crude Oil

04/2007 to 06/2007

300,000

50.00/$78.50

Crude Oil

07/2007 to 09/2007

110,000

50.00/$70.90

Crude Oil

07/2007 to 09/2007

300,000

50.00/$77.55

Crude Oil

10/2007 to 12/2007

110,000

49.00/$71.50

Crude Oil

10/2007 to 12/2007

300,000

50.00/$76.50

Crude Oil

01/2008 to 03/2008

110,000

49.00/$70.65

Crude Oil

04/2008 to 06/2008

110,000

48.00/$71.60

Crude Oil

07/2008 to 09/2008

110,000

48.00/$70.85

Crude Oil

10/2008 to 12/2008

110,000

48.00/$70.20

Natural Gas

07/2006 to 09/2006

600,000

6.00/$10.28

Natural Gas

07/2006 to 09/2006

1,000,000

6.00/$10.38

Natural Gas

10/2006 to 12/2006

600,000

6.00/$12.28

Natural Gas

10/2006 to 12/2006

1,000,000

6.00/$12.18

Natural Gas

01/2007 to 03/2007

600,000

6.00/$15.20

Natural Gas

01/2007 to 03/2007

1,000,000

6.00/$15.52

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 beyond the ceiling. For the 2006 crude oil contracts listed above, a hypothetical $1.00 change in the NYMEX price would cause a change in the gain (loss) on hedging activities of $2.7 million for the remainder of 2006. For the 2006 natural gas contracts listed above, a hypothetical $0.10 change in the NYMEX price above the ceiling price or below the floor price applied to the notional amounts would cause a change in the gain (loss) on hedging activities of $1.0 million for the remainder of 2006.

We have also entered into fixed price marketing contracts directly with end users for a portion of the natural gas we produce in Michigan. All of those contracts have built-in pricing escalators of 4% per year. Our outstanding fixed price marketing contracts at July 17, 2006 are summarized below:

Monthly Volume

2006 Price

Commodity

Period

(MMBtu)

Per MMBtu

Natural Gas

01/2002 to 12/2011

51,000

4.57

Natural Gas

01/2002 to 12/2012

60,000

4.05

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, President and Chief Executive Officer and our Vice President and 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 the end of the quarter ended June 30, 2006. Based upon their evaluation of these disclosures controls and procedures, the Chairman, President and Chief Executive Officer and the Vice President and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the end of the quarter ended June 30, 2006 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms, 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 June 30, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

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, 2005. No material change to such risk factors has occurred during the six months ended June 30, 2006.

Item 4. Submission of Matters to a Vote of Security Holders

Whiting Petroleum Corporation held its annual meeting of stockholders on May 9, 2006. At such meeting, Graydon D. Hubbard and James J. Volker were reelected as directors for terms to expire at the 2009 annual meeting of stockholders and until their successors are duly elected and qualified pursuant to the following votes:


	Shares Voted
Name of Nominee	For		Withheld
Graydon D. Hubbard		27,964,524		4,630,940
James J. Volker		30,386,221		2,209,243

The other directors of Whiting Petroleum Corporation whose terms of office continued after the 2006 annual meeting of stockholders are as follows: terms expiring at the 2007 annual meeting: Thomas L. Aller and Thomas P. Briggs and terms expiring at the 2008 annual meeting: D. Sherwin Artus, Palmer L. Moe and Kenneth R. Whiting.

The following other matter brought for vote at the 2006 annual meeting of stockholders passed by the vote indicated:


	Shares Voted
	For		Against		Abstain		Broker Non-Vote
Ratification of the appointment of Deloitte & Touche LLP as independent registered public accounting firm		32,562,054		21,138		12,272		—

Item 6. Exhibits

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

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 26th day of July, 2006.



		WHITING PETROLEUM CORPORATION

		By		/s/ James J. Volker

				James J. Volker
				Chairman, President 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

EXHIBIT INDEX


Exhibit
Number		Exhibit Description

(31.1)		Certification by Chairman, President 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)		Written Statement of the Chairman, President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

(32.2)		Written Statement of the Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

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