e10vq

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, 2005


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

1700 Broadway, Suite 2300 Denver, Colorado		80290-2300

(Address of principal executive offices)		(Zip code)

(303) 837-1661

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No £

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ No £

Number of shares of the registrant’s common stock outstanding at July 18, 2005: 29,790,722 shares.

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30, 2005 (Unaudited) AND DECEMBER 31, 2004
(In thousands)


	June 30,			December 31,
	2005			2004
	(unaudited)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	15,621		$	1,660
Accounts receivable trade, net		59,421			63,489
Deferred income taxes		9,013			2,368
Prepaid expenses and other		12,071			10,566


Total current assets		96,126			78,083

PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties		1,377,512			1,225,676
Unproved properties		12,341			6,038
Other property and equipment		6,144			4,554


Total property and equipment		1,395,997			1,236,268

Less accumulated depreciation, depletion and amortization		(284,215	)		(244,246	)


Total property and equipment-net		1,111,782			992,022


DEBT ISSUANCE COSTS		14,100			11,823

OTHER LONG-TERM ASSETS		10,753			10,278


TOTAL	$	1,232,761		$	1,092,206

See condensed notes to unaudited consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30, 2005 (Unaudited) AND DECEMBER 31, 2004
(In thousands)


	June 30,			December 31,
	2005			2004
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	24,919		$	19,815
Accrued interest		4,845			2,050
Oil and gas sales payable		6,237			4,987
Accrued employee compensation and benefits		5,445			7,808
Production taxes payable		9,497			8,254
Current portion of tax sharing liability		4,214			4,214
Current portion of long-term debt		3,242			3,167
Derivative liability		18,890			1,670
Income taxes payable and other liabilities		—			129


Total current liabilities		77,289			52,094

ASSET RETIREMENT OBLIGATIONS		35,218			31,639

PRODUCTION PARTICIPATION PLAN LIABILITY		9,848			9,579

TAX SHARING LIABILITY		28,206			26,966

LONG-TERM DEBT		367,369			325,261

DEFERRED INCOME TAXES		61,161			34,281

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY:
Common stock, $.001 par value; 75,000,000 shares authorized, 29,790,722 and 29,717,808 shares issued and outstanding as of June 30, 2005 and December 31, 2004, respectively		30			30
Additional paid-in capital		458,879			455,635
Accumulated other comprehensive loss		(11,598	)		(1,025	)
Deferred compensation		(3,395	)		(1,715	)
Retained earnings		209,754			159,461


Total stockholders’ equity		653,670			612,386


TOTAL	$	1,232,761		$	1,092,206

See condensed notes to unaudited consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF INCOME
FOR THE THREE MONTHS AND SIX MONTHS ENDED JUNE 30, 2005 AND 2004
(In thousands, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
REVENUES:
Oil and gas sales	$	115,978		$	52,874		$	221,443		$	100,510
Loss on oil and gas hedging activities		(4,890	)		(560	)		(6,945	)		(1,575	)
Gain on sale of marketable securities		—			2,382			—			2,382
Interest income and other		35			35			166			134

Total		111,123			54,731			214,664			101,451


COSTS AND EXPENSES:
Lease operating		22,110			11,144			42,939			21,693
Production taxes		7,915			3,212			14,455			6,218
Depreciation, depletion and amortization		20,735			10,761			41,082			21,490
Exploration and impairment		6,005			502			7,404			920
General and administrative		6,767			4,073			13,495			8,074
Interest expense		8,122			3,100			13,378			5,419

Total costs and expenses		71,654			32,792			132,753			63,814


INCOME BEFORE INCOME TAXES		39,469			21,939			81,911			37,637

INCOME TAX EXPENSE:
Current		3,099			—			4,737			—
Deferred		12,132			8,468			26,881			14,528

Total income tax expense		15,231			8,468			31,618			14,528


NET INCOME	$	24,238		$	13,471		$	50,293		$	23,109


NET INCOME PER COMMON SHARE, BASIC AND DILUTED	$	0.82		$	0.72		$	1.69		$	1.23


WEIGHTED AVERAGE SHARES OUTSTANDING, BASIC		29,681			18,755			29,673			18,754


WEIGHTED AVERAGE SHARES OUTSTANDING, DILUTED		29,699			18,775			29,698			18,766

See condensed notes to unaudited consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME
FOR THE YEAR ENDED DECEMBER 31, 2004 AND THE
SIX MONTHS ENDED JUNE 30, 2005 (Unaudited)
(In thousands)


									Accumulated
						Additional			Other								Total
	Common Stock					Paid-in			Comprehensive			Deferred			Retained		Stockholders’			Comprehensive
	Shares			Amount		Capital			Income (Loss)			Compensation			Earnings		Equity			Income
BALANCES—January 1, 2004		18,750		$	19	$	170,367		$	(223	)	$	—		$	89,415	$	259,578		$	19,612

Net income		—			—		—			—			—			70,046		70,046			70,046
Change in fair value of marketable securities for sale		—			—		—			3,741			—			—		3,741			3,741
Realized gain on marketable securities for sale		—			—		—			(4,835	)		—			—		(4,835	)		(4,835	)
Change in derivative instrument fair value		—			—		—			292			—			—		292			292
Issuance of stock — Equity Oil Company merger		2,237			2		43,296			—						—		43,298
Issuance of stock — secondary offering		8,625			9		239,677			—			—			—		239,686			—
Deferred compensation stock issued		106			—		2,295			—			(2,295	)		—		—			—
Amortization of deferred compensation		—			—		—			—			580			—		580			—


BALANCES—December 31, 2004		29,718			30		455,635			(1,025	)		(1,715	)		159,461		612,386		$	69,244

Net income (unaudited)																50,293		50,293			50,293
Change in derivative instrument fair value (unaudited)										(10,573	)							(10,573	)		(10,573	)
Restricted stock issued (unaudited)		85					3,407						(3,407	)
Restricted stock forfeited (unaudited)		(8	)				(181	)					181
Restricted stock used for tax withholdings (unaudited)		(4	)				(174	)										(174	)
Net tax effect arising from restricted stock activity							192											192
Amortization of deferred compensation (unaudited)													1,546					1,546


BALANCES—June 30, 2005 (unaudited)		29,791		$	30	$	458,879		$	(11,598	)	$	(3,395	)	$	209,754	$	653,670		$	39,720

See condensed notes to unaudited consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2005 AND 2004 (in thousands)


	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	50,293		$	23,109
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		41,082			21,490
Deferred income taxes		26,881			14,528
Amortization of debt issuance costs and debt discount		1,697			659
Accretion of tax sharing agreement		1,240			1,200
Amortization of deferred compensation		1,546			227
Impairment of oil and gas properties		1,928			—
Gain on sale of marketable securities		—			(2,382	)
Changes in assets and liabilities:
Accounts receivable		6,633			(6,147	)
Other assets		(1,783	)		(3,545	)
Asset retirement obligations		(128	)		(224	)
Production participation plan liability		(1,971	)		(2,436	)
Accounts payable		4,636			351
Other liabilities		5,111			451

Net cash provided by operating activities		137,165			47,281


CASH FLOWS FROM INVESTING ACTIVITIES:
Cash acquisition capital expenditures		(76,738	)		(2,874	)
Drilling capital expenditures		(53,989	)		(26,349	)
Proceeds from sale of marketable securities		—			2,677
Acquisition of Partnership interests, net of cash acquired of $26		(30,433	)		—

Net cash used by investing activities		(161,160	)		(26,546	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of 7 1/4% Senior Subordinated debt due 2012		—			148,890
Issuance of 7 1/4% Senior Subordinated debt due 2013		216,715			—
Issuance of long-term debt under credit agreement		60,000			—
Payments on long-term debt under credit agreement		(235,000	)		(185,000	)
Debt issuance costs		(3,777	)		(5,834	)
Restricted stock used for tax withholdings		(174	)		—
Net tax effect arising from restricted stock activity		192			—

Net cash provided (used) by financing activities		37,956			(41,944	)


NET CHANGE IN CASH AND CASH EQUIVALENTS		13,961			(21,209	)

CASH AND CASH EQUIVALENTS:
Beginning of period		1,660			53,585

End of period	$	15,621		$	32,376


SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for income taxes	$	5,277		$	722

Cash paid for interest	$	7,075		$	2,976

See condensed notes to unaudited consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

CONDENSED NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2005
(In thousands, except per share data)

1. BASIS OF PRESENTATION

Description of Operations — Whiting Petroleum Corporation (“Whiting” or the “Company”) is a Delaware corporation that prior to its initial public offering in November 2003 was a wholly owned indirect subsidiary of Alliant Energy Corporation (“Alliant Energy” or “Alliant”), a holding company whose primary businesses are utility companies. Whiting acquires, develops and explores for producing oil and gas properties primarily in the Rocky Mountains, Permian Basin, Gulf Coast, Michigan, Mid-Continent and California 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 intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. 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 Annual Report on Form 10-K for the year ended December 31, 2004. It is recommended that these unaudited consolidated financial statements be read in conjunction with the audited consolidated financial statements and notes included in the Company’s Form 10-K.

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. The dilutive effect of these securities was immaterial to the calculation.

Reclassifications — Certain prior period balances were reclassified to conform to the current year presentation. Those reclassifications had no impact on net income, stockholders’ equity or cash flows from operations as previously reported.

2. DERIVATIVE FINANCIAL INSTRUMENTS

Whiting is exposed to market risk in the pricing of its oil and gas production. 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. Periodically, Whiting utilizes traditional swap and collar arrangements to mitigate the impact of oil and gas price fluctuations related to its sales of oil and gas. The Company attempts to qualify the majority of these instruments as cash flow hedges for accounting purposes.

During the first six months of 2005 and 2004, the Company recognized losses of $6,945 and $1,575, respectively, related to its hedging activities. In addition, at June 30, 2005, Whiting’s

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remaining cash flow hedge positions resulted in a pre-tax liability of $18,890 of which $11,598 was recorded as a component of accumulated other comprehensive income and $7,292 was recorded as a current deferred tax asset. See Note 4 for restrictions in our credit agreement relating to hedging activities.

3. ASSET RETIREMENT OBLIGATIONS

The Company recognizes the fair value of its liability for plugging and abandoning its oil and natural gas wells in the financial statements by capitalizing that cost as a part of the cost of the related asset. The additional carrying amount is depleted over the estimated lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and includes the abandonment obligation for certain onshore and offshore facilities located in California. The discounted obligation is accreted at the end of each accounting period through charges to depreciation, depletion and amortization expense. If the obligation is settled for other than the carrying amount, then a gain or loss is recognized upon settlement.

The following table provides a reconciliation of the Company’s asset retirement obligations for the six months ended June 30, 2005 and 2004, respectively.


	Six Months Ended			Six Months Ended
	June 30, 2005			June 30, 2004
Beginning asset retirement obligation	$	31,639		$	23,021
Additional liability incurred		2,593			423
Accretion expense		1,114			760
Liabilities settled		(128	)		(224	)


Ending asset retirement obligation	$	35,218		$	23,980

No revisions have been made to the timing or the amount of the original estimate of undiscounted cash flows during the first six months of 2005 or 2004.

4. LONG-TERM DEBT

Long-term debt consisted of the following at June 30, 2005 and December 31, 2004:


	June 30,			December 31,
	2005			2004
Credit Agreement	$	0		$	175,000
7-1/4% Senior Subordinated Notes due 2012		150,545			150,261
7-1/4% Senior Subordinated Notes due 2013		216,824			0
Alliant Energy		3,242			3,167

Total debt		370,611			328,428
Current portion of long-term debt		(3,242	)		(3,167	)

Long-term debt	$	367,369		$	325,261

Credit Agreement — Whiting Oil and Gas Corporation has a $750.0 million credit agreement with a syndicate of banks that, as of June 30, 2005, had a borrowing base of $550.0 million. The borrowing base under the credit agreement is determined in the discretion of the lenders based on

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the collateral value of the 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, 2005, there was no outstanding principal balance under the credit agreement.

The credit agreement provides for interest only payments until September 23, 2008, when the entire amount borrowed is due. Whiting Oil and Gas Corporation may, throughout the four year 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 $30.0 million. As of June 30, 2005, 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 0.250% 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, 2005, the six month LIBOR rate was 3.71%.

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 contracts, 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 of greater than 1 to 1. The Company is in compliance with all credit agreement provisions, including those that require the Company to hedge at least 60% but not more than 75% of its total forecasted proved developed producing production through December 31, 2005 in the form of costless collars or fixed price swaps, with a minimum floor price of $35 per barrel of oil or $4.50 per million British Thermal Units (MMBtu). After December 31, 2005, the credit agreement will not require the Company to hedge any of the Company’s production, but will continue to limit the Company’s hedging to a maximum of 75% of the Company’s forecasted proved developed producing production. In addition, while the credit agreement allows the Company’s subsidiaries to make payments to the Company so that it may pay interest on its senior subordinated notes, it does not allow the Company’s subsidiaries to make payments to it to pay principal on the senior subordinated notes. The Company was in compliance with its covenants under the credit agreement as of June 30, 2005. The credit agreement is secured by a first lien on substantially all of Whiting Oil and Gas Corporation’s assets. Whiting Petroleum Corporation and 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 substantially all of its assets as security for its guarantee.

7-1/4% Senior Subordinated Notes — On April 19, 2005, the Company issued $220.0 million aggregate principal amount of its 7-1/4% Senior Subordinated Notes due 2013. The net proceeds of the offering were used to repay debt outstanding under Whiting Oil and Gas Corporation’s credit agreement. The 7-1/4% Senior Subordinated Notes due 2013 were issued at 98.507% of par and

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the associated discount is being amortized to interest expense over the term of the notes. Based on the market price of the 7-1/4% Senior Subordinated Notes due 2013, their estimated fair value was $223.6 million as of June 30, 2005.

In May 2004, the Company issued $150.0 million aggregate principal amount of its 7-1/4% Senior Subordinated Notes due 2012. The 7-1/4% Senior Subordinated Notes due 2012 were issued at 99.26% of par and the associated discount is being amortized to interest expense over the term of the notes. Based on the market price of the 7-1/4 % Senior Subordinated Notes due 2012, their estimated fair value was $153.2 million as of June 30, 2005.

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 limit the discretion of the Company’s management in operating the Company’s business. In addition, Whiting Oil and Gas Corporation’s credit agreement restricts the ability of the Company’s subsidiaries to make certain payments to the Company. The Company was in compliance with these covenants as of June 30, 2005. Both of the Company’s subsidiaries, Whiting Oil and Gas Corporation and Equity Oil Company (the “Guarantors”), have fully, unconditionally, jointly and severally guaranteed the Company’s obligations under the notes. All of the Company’s subsidiaries other than the Guarantors are minor 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 million of its 7-1/4% Senior Subordinated Notes due 2012. 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 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 million for the six month period. The LIBOR rate at June 30, 2005 was 3.71%. As of June 30, 2005, we have recorded a long term derivative asset of $1.5 million related to the interest rate swap, which has been designated as a fair value hedge, with a corresponding debt increase to the 7-1/4% Senior Subordinated Notes due 2012.

Short-Term Debt — In conjunction with the Company’s initial public offering in November 2003, the Company issued a promissory note payable to Alliant Energy in the aggregate principal amount of $3.0 million. The promissory note bears interest at an annual rate of 5%. All principal and interest on the promissory note are due on November 25, 2005.

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5. 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. No participating employee may be granted options for more than 300,000 shares of common stock, stock appreciation rights with respect to more than 300,000 shares of common stock or more than 150,000 shares of restricted stock during any calendar year. This plan prohibits the repricing of outstanding stock options without stockholder approval. During the first six months of 2005, the Company granted 84,652 shares of restricted stock under this plan and 8,065 shares were forfeited. The new shares of restricted stock were recorded at fair value of $3.4 million and are being amortized to general and administrative expense over their three year vesting period.

6. PRODUCTION PARTICIPATION PLAN

The Company has a Production Participation Plan for all employees. On an annual basis, interests in oil and gas properties acquired or developed during the year are allocated to the plan on a discretionary basis. Once allocated, the interests (not legally conveyed) are fixed. Allocations prior to 1995 consisted of 2% — 3% overriding royalty interests. Allocations since 1995 have been 2% — 5% net revenue interests. Prior to plan year 2004, plan participants generally vested ratably over their initial five years of employment in all income allocated to the plan on their behalf and forfeitures were re-allocated among other Plan participants. The Production Participation Plan was modified in 2004 to provide that (1) for years 2004 and beyond, employees will vest at a rate of 20% per year with respect to the income allocated to the plan for such year; (2) employees will become fully vested at age 65, regardless of when their interests would otherwise vest; and (3) for years 2004 and beyond, if there are forfeitures, the interests will inure to the benefit of the Company.

7. TAX SEPARATION AND INDEMNIFICATION AGREEMENT WITH ALLIANT ENERGY

In connection with Whiting’s initial public offering in November 2003, 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 basis 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 basis of the Company’s assets. This additional basis is 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 to 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 basis 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 $62.0 million. The Company has estimated total payments to Alliant will approximate $49.0 million given the discounting affect of the final payment in 2014. The Company has discounted all cash payments to Alliant at the date of the Tax Separation Agreement.

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The initial recording of this transaction in November 2003 resulted in a $57.2 million increase in deferred tax assets, a $28.6 million discounted payable to Alliant Energy and a $28.6 million increase to stockholders’ equity. The Company will monitor the estimate of when payments will be made and adjust the accretion of this liability on a prospective basis. During the first six months of 2005, the Company did not make any payments under this agreement but did recognize $1.2 million of accretion expense which is included as a component of interest expense. The Company’s estimate of payments to be made in 2005 under this agreement of $4.2 million is reflected as a current liability at June 30, 2005.

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 Alliant liability. For purposes of this calculation, the Company’s management has assumed that no such change will occur during the term of this agreement.

8. COMMITMENTS AND CONTINGENCIES

The Company leases 87,000 square feet of administrative office space under an operating lease arrangement through October 31, 2010. Rental expense for the initial six months of 2005 and 2004 was $725 and $481, respectively. A summary of future minimum lease payments under this non-cancelable operating lease as of June 30, 2005 is as follows (in thousands):


Year Ending December 31, 2005	$	735
Year Ending December 31, 2006		1,469
Year Ending December 31, 2007		1,469
Year Ending December 31, 2008		1,469
Year Ending December 31, 2009		1,469
Year Ending December 31, 2010		1,224


Total	$	7,835

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 or results of operations.

9. ACQUISITIONS

Limited Partnership Interests — On June 23, 2005, Whiting Oil and Gas Corporation acquired all of the limited partnership interests in three institutional partnerships managed by its wholly-owned subsidiary, Whiting Programs, Inc. The purchase price was $30.5 million for estimated proved reserves of approximately 17.4 Bcfe, resulting in a cost of approximately $1.75 per Mcfe of estimated proved reserves. Current production attributable to the property interests is approximately 4.0 MMcfe per day. The partnership properties are located primarily in Louisiana, Texas, Arkansas, Oklahoma and Wyoming. The effective date of the acquisition is January 1, 2005 and the acquisition was funded with cash on hand.

As this acquisition was recorded using the purchase method of accounting, the results of operations from the acquisition are included with our results from June 23, 2005 forward. The table below summarizes the allocation of the purchase price based on the acquisition date fair value of the assets acquired and the liabilities assumed (in thousands):

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Purchase Price:
Cash paid, net of cash acquired of $26	$	30,433


Allocation of Purchase Price:
Working capital	$	2,096
Oil and gas properties		30,022
Long-term liabilities		(1,685	)

Total	$	30,433

Green River Basin Acquisition - On March 31, 2005, the Company acquired operated interests in five producing gas fields in the Green River Basin of Wyoming. The purchase price was $65.0 million for estimated proved reserves as of the effective date of the acquisition of approximately 50.5 Bcfe, resulting in a cost of $1.29 per Mcfe of estimated proved reserves. Future development costs of the proved undeveloped reserves are estimated at approximately $14 million. Whiting operates approximately 95% of the net daily production from the properties, which was estimated to be 6.3 million Mcfe per day at the acquisition date. Whiting funded the acquisition through borrowings under Whiting Oil and Gas Corporation’s credit agreement and with cash on hand.

10. SUBSEQUENT EVENTS

In July 2005, Whiting entered into two purchase and sale agreements with Celero Energy, LP to acquire the operated interest in two producing oil and gas fields, one in the Oklahoma Panhandle and the other in the Permian Basin of West Texas. The separate closings are expected to occur on August 4, 2005 and October 4, 2005, subject to standard conditions to closing. The total purchase price will be approximately $802 million, or $1.09 per thousand cubic feet equivalent (Mcfe) of estimated proved reserves. The purchase and sale agreements provide that Whiting will pay Celero $343 million in cash at the August closing and $442 million in cash at the October closing, as well as issue 441,500 shares of Whiting common stock to Celero at the October closing. Based on recent trading, this stock has a value of approximately $17 million. A deposit of $80.2 million was paid on July 26, 2005, of which $ 80.0 million was funded with borrowings under the Credit Agreement. The effective date of both transactions will be July 1, 2005.

Total proved reserves for the properties to be acquired are estimated at 734 billion cubic feet equivalent (Bcfe), as of July 1, 2005, 94% of which is oil and 43% of which is developed. In aggregate, the properties cover an area of approximately 112,000 acres (net). Upon completion of the acquisitions, Whiting will operate approximately 95% of the properties, which produced at an average net daily rate of approximately 7,510 barrels of oil and 2.8 million cubic feet of gas, or 47.8 million cubic feet equivalent (MMcfe), during the first quarter of 2005. Substantially all of the properties to be acquired from Celero provide potential for enhanced recovery (primarily waterflooding and CO₂ injection), as well as reserve growth associated with development and exploratory drilling. Whiting estimates future development costs of $534 million related to the Celero properties, of which 80% will be incurred over the next 5 -1/2 years.

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

Unless the context otherwise requires, the terms “Whiting,” “we,” “us,” “our” or “ours” when used in this Item refer to Whiting Petroleum Corporation, together with its 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 natural 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 and properties; 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 natural gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and natural gas operations; our inability to access oil and natural gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and natural 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 natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and natural gas industry; and risks arising out of our hedging transactions. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this report.

Overview

We are engaged in oil and natural gas exploitation, acquisition, exploration and production activities primarily in the Rocky Mountains, Permian Basin, Gulf Coast, Michigan, Mid-Continent and California regions of the United States. Over the last four 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

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attractive rates of return that provided a foothold in a new area of interest or 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 management is 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.

On June 23, 2005, we acquired all of the limited partnership interests in three institutional partnership managed by our wholly-owned subsidiary, Whiting Programs, Inc., acquiring total estimated proved reserves as of the effective date of the acquisition of approximately 17.4 Bcfe for a purchase price of $30.5 million. On March 31, 2005, we acquired operated interests in five producing gas fields in the Green River Basin of Wyoming, acquiring total estimated proved reserves as of the effective date of the acquisition of approximately 50.5 Bcfe for a purchase price of $65.0 million. We completed seven separate acquisitions of producing properties during 2004 with a combined purchase price of $535.1 million for total estimated proved reserves as of the effective dates of the acquisitions of approximately 436.1 Bcfe. 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 revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

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Results of Operations

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Selected Operating Data:


	Six Months Ended
	June 30,
	2005			2004
Net production:
Natural gas (MMcf)		14,977			10,970
Oil (MBbls)		2,953			1,301
MMcfe		32,695			18,776
Oil and gas sales (in thousands)
Natural gas	$	85,518		$	58,263
Oil	$	135,925		$	42,247
Average sales prices:
Natural gas (per Mcf)	$	5.71		$	5.31
Effect of natural gas hedges on average price (per Mcf)	$	—		$	—

Natural gas net of hedging (per Mcf)	$	5.71		$	5.31


Oil (per Bbl)	$	46.03		$	32.47
Effect of oil hedges on average price (per Bbl)	$	(2.35	)	$	(1.21	)

Oil net of hedging (per Bbl)	$	43.68		$	31.26


Additional data (per Mcfe):
Sales price, net of hedging	$	6.56		$	5.27
Lease operating expenses	$	1.31		$	1.16
Production taxes	$	0.44		$	0.33
Depreciation, depletion and amortization expense	$	1.26		$	1.14
General and administrative expenses	$	0.41		$	0.43

Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased approximately $120.9 million to $221.4 million in the first six months of 2005 compared to the first six months of 2004. Sales are a function of sales volumes and average sales prices. Our sales volumes increased 74.1% between periods on an Mcfe basis. The volume increase resulted primarily from acquisition activities and successful drilling activities over the past year that produced new sales volumes that more than offset natural decline. Our production volumes in the first half of 2005 were less than anticipated due in part to delays in rig availability that have caused delays in our development drilling program and temporary pipeline shut downs and workover activity in the first quarter of 2005. Our average price for natural gas sales increased 7.5% and our average price for crude oil increased 41.8% between periods.

Loss on Oil and Natural Gas Hedging Activities. We hedged 60% of our natural gas volumes during the first six months of 2005 and 23% of our natural gas volumes during the first six months of 2004 incurring no hedging loss or gain in either period. We hedged 60% of our oil volumes during the first six months of 2005 incurring a hedging loss of $6.9 million, and 46% of our oil volumes during the first six months of 2004 incurring a hedging loss of $1.6 million. See Item 3, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil and natural gas hedges as of July 29, 2005.

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Lease Operating Expenses. Our lease operating expense increased approximately $21.2 million to $42.9 million in the first six months of 2005 compared to the first six months of 2004. The increase resulted primarily from costs associated with new property acquisitions over the past year. Our lease operating expense as a percentage of oil and gas sales decreased from 21.6% during the first six months of 2004 to 19.4% during the first six months of 2005 as lease operating costs increases did not keep pace with sales price increases. Our lease operating expenses per Mcfe increased from $1.16 during the first six months of 2004 to $1.31 during the same period in 2005. The increase of 12.9% was primarily caused by price inflation caused by increased demand for goods and services in the industry.

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. Due to our broad asset base, we expect our production tax rate to vary between 6.0% to 6.5% of oil and natural gas sales revenue. Our production taxes for the initial six months of 2005 and 2004 were 6.5% and 6.2% of oil and natural gas sales, respectively.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $19.6 million to $41.1 million during the first six months of 2005 compared to $21.5 million for the same period in 2004. The increase resulted from increased production due to our recent acquisitions and an increase in the DD&A rate. On an Mcfe basis, the rate increased from $1.14 during 2004 to $1.26 in 2005. The increase in rate is primarily due to our 2004 all sources finding, development and acquisition cost which averaged $1.28 per Mcfe, which was higher than our historical average rate. Also contributing to the DD&A rate increase is the increase in the Company’s drilling expenditures as costs to develop proved undeveloped reserves are not considered for DD&A purposes until incurred. Changes to the pricing environment can also impact our DD&A rate. Price increases allow for longer economic production lives and corresponding increased reserve volumes and, as a result, lower depletion rates. Price decreases have the opposite effect. The components of our DD&A expense were as follows (in thousands):


	Six Months Ended June 30,
	2005		2004
Depletion	$	39,408	$	20,370
Depreciation		560		360
Accretion of asset retirement obligations		1,114		760

Total	$	41,082	$	21,490

Exploration and Impairment. Our exploration and impairment costs increased $6.5 million to $7.4 million in the first six months of 2005 compared to the first six months of 2004.


	Six Months Ended June 30,
	2005		2004
Exploration	$	5,476	$	920
Impairment		1,928		—

Total	$	7,404	$	920

The higher exploratory costs resulted from three exploratory dry holes drilled during 2005 totaling $1.8 million and increased geological and geophysical costs to support the increase in our development drilling budget from $79.4 million in 2004 to between $130 million and $150 million in

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2005. The impairment charge in 2005 relates to unrecoverable costs associated with our investment in the Cherokee Basin of Kansas.

General and Administrative Expenses. We report general and administrative expense net of reimbursements. The components of our general and administrative expense were as follows:


	Six Months Ended June 30,
	2005			2004
General and administrative expenses	$	18,639		$	10,630
Reimbursements		(5,144	)		(2,556	)

General and administrative expense, net	$	13,495		$	8,074

General and administrative expense before reimbursements increased $8.0 million to $18.6 million during the initial six months of 2005 compared to $10.6 million during the same period in 2004. The largest components of the increase related to costs associated with our production participation plan of $3.1 million and increased salaries with related benefits and taxes of $3.5 million. The increased cost of the production participation plan was caused primarily by increased production and increased average prices between the first six months of each year. The increase in salaries was due primarily to an increase in the employee base due to our continued growth. The increase in reimbursements was caused by an increase in operated properties due to acquisition and drilling activity during the last half of 2004 and the first six months of 2005. Our general and administrative expense decreased between periods from $0.43 to $0.41 per Mcfe due to the efficiencies of spreading fixed costs over a larger production base. As a percentage of oil and gas sales, our general and administrative expense also decreased from 8.0% during the first six months of 2004 to 6.1% during the same period in 2005 as general and administrative costs increased slower than oil and gas sales prices.

Interest Expense. The components of our interest expense were as follows:


	Six Months Ended June 30,
	2005		2004
Credit Agreement	$	2,433	$	1,975
7-1/4% Senior Subordinated Notes due 2012		4,724		1,510
7-1/4% Senior Subordinated Notes due 2013		3,209		—
Alliant Energy		75		75
Amortization of debt issue costs and debt discount		1,697		659
Accretion of tax sharing liability		1,240		1,200

Total interest expense	$	13,378	$	5,419

The increase in interest expense is primarily due to the May 2004 issuance of $150.0 million of 7-1/4% Senior Subordinated Notes due 2012 and the April 2005 issuance of $220.0 million of 7-1/4% Senior Subordinated Noted due 2013. The additional cash interest cost and additional amortization of debt issue costs and debt discount in 2005 is due to the greater number of days that each instrument was outstanding versus the prior year. In August of 2004, $75.0 million of the face amount of the 7-1/4% Senior Subordinated Notes due 2012 notes were swapped to a floating rate. At May 1, 2005, the floating rate component was set at 5.76% through November 1, 2005.

Our weighted average debt outstanding during the initial six months of 2005 was $347 million versus $160 million during the initial six months of 2004. Our weighted average effective cash interest rate was 6.0% during the initial six months of 2005 versus 4.45% during the initial six months of

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2004. After inclusion of noncash 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 7.1% during the initial six months of 2005 versus 5.9% during the initial six months of 2004.

Income Tax Expense. Income tax expense totaled $31.6 million for the first six months of 2005 and $14.5 million for the same period in 2004, resulting in effective income tax rates of 38.6% for both periods. We did not show current income tax expense in the first quarter of 2004 since our net operating loss carryforward from 2003 was sufficient to offset taxable income generated during the first quarter of 2004. By the end of the 2004 tax year, this net operating loss carryforward was fully utilized. During the first six months of 2005, we estimate that our full year 2005 cash tax liability would approximate 15% of the full year 2005 tax provision and have reflected this as current tax expense.

Net Income. Net income increased from $23.1 million during the first six months of 2004 to $50.3 million during the first six months of 2005. The primary reasons for this increase included 24% higher crude oil and natural gas prices net of hedging between periods and a 74.1% increase in equivalent volumes sold, offset by higher lease operating expense, production taxes, general and administrative, DD&A, interest and exploration and impairment costs in the initial six months of 2005 due to our growth.

Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004

Selected Operating Data:


	Three Months Ended
	June 30,
	2005			2004
Net production:
Natural gas (MMcf)		7,446			5,450
Oil (MBbls)		1,489			652
MMcfe		16,380			9,362
Oil and gas sales (in thousands)
Natural gas	$	44,976		$	30,653
Oil	$	71,002		$	22,221
Average sales prices:
Natural gas (per Mcf)	$	6.04		$	5.63
Effect of natural gas hedges on average price (per Mcf)	$	—		$	—

Natural gas net of hedging (per Mcf)	$	6.04		$	5.63


Oil (per Bbl)	$	47.68		$	34.08
Effect of oil hedges on average price (per Bbl)	$	(3.28	)	$	(0.86	)

Oil net of hedging (per Bbl)	$	44.40		$	33.22


Additional data (per Mcfe):
Sales price, net of hedging	$	6.78		$	5.59
Lease operating expenses	$	1.35		$	1.19
Production taxes	$	0.48		$	0.34
Depreciation, depletion and amortization expense	$	1.27		$	1.15
General and administrative expenses	$	0.41		$	0.44

Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased approximately $63.1 million to $116.0 million in the second quarter of 2005 compared to the second quarter of 2004. Sales are a function of sales volumes and average sales prices. Our sales volumes increased 75.0%

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between periods on an Mcfe basis. The volume increase resulted primarily from acquisition activities and also from successful drilling activities over the past year that produced new sales volumes that more than offset natural decline. Our production volumes in the second quarter of 2005 were less than anticipated due in part to delays in rig availability that have caused delays in our development drilling program. Our average price for natural gas sales increased 7.3% and our average price for crude oil increased 39.9% between periods.

Loss on Oil and Natural Gas Hedging Activities. We hedged 60% of our natural gas volumes during the second quarter of 2005 incurring no hedging loss or gain. We did not hedge our natural gas volumes during the second quarter of 2004. We hedged 50% of our oil volumes during the second quarter of 2005 incurring a hedging loss of $4.9 million, and 46.0% of our oil volumes during the second quarter of 2004 incurring a loss of $0.6 million. See Item 3, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil and natural gas hedges as of July 29, 2005.

Lease Operating Expenses. Our lease operating expense increased approximately $11.0 million to $22.1 million in the second quarter of 2005 compared to the second quarter of 2004. The increase resulted primarily from costs associated with new property acquisitions over the past year. Our lease operating expense as a percentage of oil and gas sales decreased from 21.1% during the second quarter of 2004 to 19.1% during the second quarter of 2005 as lease operating costs increases did not keep pace with sales price increases. Our lease operating expenses per Mcfe increased from $1.19 during the second quarter of 2004 to $1.35 during the second quarter of 2005. The increase of 13.4% was primarily caused by price inflation caused by increased demand for goods and services in the industry.

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. Due to our broad asset base, we expect our production tax rate to vary between 6.0% to 6.5% of oil and natural gas sales revenue. Our production taxes for the second quarters of 2005 and 2004 were 6.8% and 6.1% of oil and natural gas sales, respectively. The rate of 6.8% in the second quarter of 2005 was higher than our anticipated rate going forward due to corrections of prior period returns that occurred during the quarter.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $9.9 million to $20.7 million during the second quarter of 2005 compared to $10.8 million for the same period in 2004. The increase resulted from increased production due to our recent acquisitions and an increase in the DD&A rate. On an Mcfe basis, the rate increased from $1.15 during 2004 to $1.27 in 2005. The increase in rate is primarily due to our 2004 all sources finding, development and acquisition cost which averaged $1.28 per Mcfe, which was higher than our historical average rate. Also contributing to the DD&A rate increase is the increase in the Company’s drilling expenditures as costs to develop proved undeveloped reserves are not considered for DD&A purposes until incurred. Changes to the pricing environment can also impact our DD&A rate. Price increases allow for longer economic production lives and corresponding increased reserve volumes and, as a result, lower depletion rates. Price decreases have the opposite effect. The components of our DD&A expense were as follows (in thousands):

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	Three Months Ended June 30,
	2005		2004
Depletion	$	19,889	$	10,201
Depreciation		290		180
Accretion of asset retirement obligations		556		380

Total	$	20,735	$	10,761

Exploration and Impairment. Our exploration costs increased $5.5 million to $6.0 million in the second quarter of 2005 compared to the same quarter of 2004.


	Three Months Ended June 30,
	2005		2004
Exploration	$	4,077	$	502
Impairment		1,928		—

Total	$	6,005	$	502

The higher exploratory costs resulted from two exploratory dry holes drilled during the second quarter 2005 totaling $1.7 million and increased geological and geophysical costs to support the increase in our development drilling budget from $79.4 million in 2004 to between $130 million and $150 million in 2005. The impairment charge in the second quarter of 2005 relates to unrecoverable costs associated with our investment in the Cherokee Basin of Kansas.

General and Administrative Expenses. We report general and administrative expense net of reimbursements. The components of our general and administrative expense were as follows:


	Three Months Ended June 30,
	2005			2004
General and administrative expenses	$	9,384		$	5,333
Reimbursements		(2,617	)		(1,260	)

General and administrative expense, net	$	6,767		$	4,073

General and administrative expense before reimbursements increased $4.1 million to $9.4 million during the second quarter of 2005 compared to $5.3 million during the same quarter of 2004. The largest components of the increase related to costs associated with our production participation plan of $1.6 million and increased salaries with related benefits and taxes of $1.7 million. The increased cost of the production participation plan was caused primarily by increased production and increased average prices between the second quarters of each year. The increase in salaries was due primarily to an increase in the employee base due to our continued growth. The increase in reimbursements was caused by an increase in operated properties due to acquisition and drilling activity during the last half of 2004 and the first six months of 2005. Our general and administrative expense decreased between periods from $0.44 to $0.41 per Mcfe due to the efficiencies of spreading fixed costs over a larger production base. As a percentage of oil and gas sales, our general and administrative expense also decreased from 7.7% during the second quarter of 2004 to 5.8% during the second quarter of 2005 as general and administrative costs increased slower than oil and gas sales prices.

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Interest Expense. The components of our interest expense were as follows:


	Three Months Ended June 30,
	2005		2004
Credit Agreement	$	616	$	576
7-1/4% Senior Subordinated Notes due 2012		2,624		1,510
7-1/4% Senior Subordinated Notes due 2013		3,210		—
Alliant Energy		37		37
Amortization of debt issue costs and debt discount		1,015		377
Accretion of tax sharing liability		620		600

Total interest expense	$	8,122	$	3,100

Our weighted average debt outstanding during the second quarter of 2005 was $372 million versus $151 million during the second quarter of 2004. Our weighted average effective cash interest rate was 6.97% during the second quarter of 2005 versus 5.6% during the second quarter of 2004. After inclusion of noncash 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 8.0% during the second quarter of 2005 versus 6.9% during the second quarter of 2004.

Income Tax Expense. Income tax expense totaled $15.2 million for the second quarter of 2005 and $8.5 million for the same quarter in 2004, resulting in effective income tax rates of 38.6% for both periods. We did not show current income tax expense in the second quarter of 2004 since our net operating loss carryforward from 2003 was sufficient to offset taxable income generated during the second quarter of 2004. By the end of the 2004 tax year, this net operating loss carryforward was fully utilized. During the second quarter of 2005, we estimate that our full year 2005 cash tax liability would approximate 15% of the full year 2005 tax provision and have reflected this as current tax expense.

Net Income. Net income increased from $13.5 million during the second quarter of 2004 to $24.2 million during the second quarter of 2005. The primary reasons for this increase included 21% higher crude oil and natural gas prices net of hedging between periods and a 75.0% increase in equivalent volumes sold, offset by higher lease operating expense, production taxes, general and administrative, DD&A, interest and exploration and impairment costs in the second quarter of 2005 due to our growth.

Liquidity and Capital Resources

Overview. At December 31, 2004, our debt to total capitalization ratio was 34.9%, we had $1.7 million of cash on hand and $612.4 million of stockholders’ equity. In the first half of 2005, we generated an additional $137.2 million from operating activities and $38.0 million from financing activities. We used these sources of cash in the first half of 2005 to finance acquisitions of $107.2 million and drilling capital expenditures of $54.0 million. At June 30, 2005, our debt to total capitalization ratio was 36.2%, we had $15.6 million of cash on hand and $653.7 million of stockholders’ equity.

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We continually evaluate our capital needs and compare them to our capital resources. Our budgeted capital expenditures for the further development of our property base are $130.0 million to $150.0 million during 2005, of which we spent $54.0 million in the first six months of 2005. Our 2005 budget is an increase from the $79.4 million spent on capitalized development during 2004 and the $40.3 spent in 2003. We also spent $107.2 million on acquisitions in the first half of 2005 and $452.7 million on acquisitions in the second half of 2004, funded primarily by borrowings under Whiting Oil and Gas Corporation’s credit agreement. A portion of the borrowings for the 2004 acquisitions were repaid in the fourth quarter of 2004 using approximately $240 million of proceeds from our secondary offering of 8.6 million shares of common stock. Although we have no specific budget for property acquisitions, we will continue to seek property acquisition opportunities that complement our existing core property base. We expect to fund our 2005 development expenditures from internally generated cash flow and cash on hand. If attractive acquisition opportunities arise or development expenditures exceed $150.0 million, then we believe that we could finance the additional capital expenditures with cash on hand, operating cash flow, borrowings under our credit agreement, issuances of additional equity or debt securities, or development 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 $750.0 million credit agreement with a syndicate of banks that, as of June 30, 2005, provided a borrowing base of $550.0 million. The borrowing base under the credit agreement is determined in the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders and is subject to regular redetermination on May 1 and November 1 of each year as well as special redeterminations described in the credit agreement. On April 19, 2005, we repaid the entire outstanding principal balance of $215.0 million under the credit agreement with net proceeds from our 7-1/4% Senior Subordinated Notes due 2013 and cash on hand. See a further discussion of this transaction below. As of June 30, 2005, there was no outstanding principal balance under the credit agreement.

The credit agreement provides for interest only payments until September 23, 2008, when the entire amount borrowed is due. We 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 our account from time to time in an aggregate amount not to exceed $30.0 million of the amount of the borrowing base available at the time of the request. As of June 30, 2005, letters of credit totaling $0.3 million were outstanding under the credit agreement.

Interest accrues, at our 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. We have consistently chosen the LIBOR rate option since it delivers the lowest effective interest rate. Commitment fees of 0.250% 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, 2005, the LIBOR rate was 3.71%.

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, change material contracts, 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 of greater than 1 to 1. We are in compliance with the credit agreement provision that requires us to hedge at least 60%, but not more than 75%, of our total forecasted Proved Developed Producing (PDP) production for the period

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November 1, 2004 through December 31, 2005 in the form of costless collars or fixed price swaps, with a minimum floor price of $35 per barrel of oil or $4.50 per MMbtu of natural gas. After December 31, 2005, the credit agreement will not require us to hedge any of our production, but will continue to limit our hedging to a maximum of 75% of our forecasted PDP production. In addition, while the credit agreement allows our subsidiaries to make payments to us so that we may pay interest on our senior subordinated notes, it does not allow our subsidiaries to make payments to us to pay principal on the senior subordinated notes. We were in compliance with our covenants under the credit agreement as of June 30, 2005. The credit agreement is secured by a first lien on substantially all of Whiting Oil and Gas Corporation’s assets. Whiting Petroleum Corporation and 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 substantially all of its assets as security for its guarantee.

7-1/4% Senior Subordinated Notes. On April 19, 2005, we issued $220.0 million aggregate principal amount of our 7-1/4% Senior Subordinated Notes due 2013. The net proceeds of the offering were used to repay debt outstanding under Whiting Oil and Gas Corporation’s credit agreement. The 7-1/4% Senior Subordinated Notes due 2013 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 aggregate principal amount of our 7-1/4% Senior Subordinated Notes due 2012. The 7-1/4% Senior Subordinated Notes due 2012 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 are substantially identical and 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 limit the discretion of our management in operating our business. We were in compliance with these covenants as of June 30, 2005. 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.

Alliant Energy Promissory Note. In conjunction with our initial public offering in November 2003, we issued a promissory note payable to Alliant Energy Corporation, our former parent company, in the aggregate principal amount of $3.0 million. The note bears interest at an annual rate of 5%. All principal and interest on the promissory note are due on November 25, 2005.

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. Pursuant to this agreement, we and Alliant Energy made a tax election with the effect that the tax basis 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 basis of our assets. This additional basis is 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 to 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 basis not

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occurred. In 2014, we will be obligated to pay Alliant Energy the present value of the remaining tax benefits assuming all such tax benefits will be realized in future years. The initial recording of this transaction in November 2003 resulted in a $57.2 million increase in deferred tax assets, a $28.6 million discounted payable to Alliant Energy and a $28.6 million increase to stockholders’ equity. During 2004 and the first half of 2005, we did not make any payments under this agreement but did recognize $2.4 million and $1.2 million, respectively, of accretion expense, which is included as a component of interest expense. Our estimate of payments to be made under this agreement of $4.2 million in 2005 is reflected as a current liability at June 30, 2005.

Schedule of Contractual Obligations. The following table summarizes our obligations and commitments as of June 30, 2005 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 since we cannot determine with accuracy the timing of future loan advances and repayments and the future interest rate to be charged under floating rate instruments. During August 2004, we entered into an interest rate swap on $75.0 million of our $150.0 million fixed rate 7-1/4% Senior Subordinated Notes due 2012. The amount of interest we expect to pay relating to the $75.0 million of our 7-1/4% Senior Subordinated Notes Due 2012 that remain at a fixed interest rate is $5.4 million annually through the term of the notes. The amount of interest we expect to pay relating to the $220.0 million of our 7-1/4% Senior Subordinated Notes Due 2013 is $16.0 million annually through the term of the notes.


	Payments due by period
			Less than 1						More than
Contractual Obligations	Total		year		1-3 years		3-5 years		5 years
Long-Term Debt	$	370,611	$	3,242		—		—	$	367,369
Operating Lease		7,835		1,469	$	2,938	$	2,938		490
Tax Separation and Indemnification Agreement with Alliant Energy⁽¹⁾		32,420		4,214		8,273		6,961		12,972

Total	$	410,866	$	8,925	$	11,211	$	9,899	$	380,831


(1)		Amounts shown are estimates based on estimated future income tax benefits from the increase in tax basis 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, 2005 increased to 50% of the actual price received in excess of $20.16 per barrel. As of June 30, 2005, approximately 41,000 net barrels of crude oil per month (8.6% of June 2005 estimated 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 half of 2005, we paid $3.2 million under this agreement. As of June 30, 2005, we have accrued an additional $0.6 million as currently payable.

New Accounting Policies

None.

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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, 2004. No material changes to such information have occurred during the six months ended June 30, 2005.

Effects of Inflation and Pricing

We experienced increased costs during 2004 and the first half of 2005 due to increased demand for oil field products and services. The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. When prices decline, associated costs do not necessarily decline at the same rate. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural 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 natural gas could result in increases in the cost of material, services and personnel.

Acquisition of Limited Partnership Interests

On June 23, 2005, Whiting Oil and Gas Corporation acquired all of the limited partnership interests in three institutional partnerships managed by its wholly-owned subsidiary, Whiting Programs, Inc. The purchase price was $30.5 million for estimated proved reserves of approximately 17.4 Bcfe, resulting in a cost of approximately $1.75 per Mcfe of estimated proved reserves. Current production attributable to the property interests is approximately 4.0 MMcfe per day. The partnership properties are located primarily in Louisiana, Texas, Arkansas, Oklahoma and Wyoming. The effective date of the acquisition is January 1, 2005 and the acquisition was funded with cash on hand. The acquisition of the limited partnerships increases the presence of Whiting in certain areas and provides additional exploration and production operations. As this acquisition was recorded using the purchase method of accounting, the results of operations from the acquisition are included with our results from June 23, 2005 forward.

Acquisition of Celero Energy, LP

In July 2005, Whiting entered into two purchase and sale agreements with Celero Energy, LP to acquire the operated interest in two producing oil and gas fields, one in the Oklahoma Panhandle and the other in the Permian Basin of West Texas. The separate closings are expected to occur on August 4, 2005 and October 4, 2005, subject to standard conditions to closing. The total purchase price will be approximately $802 million, or $1.09 per thousand cubic feet equivalent (Mcfe) of estimated proved reserves. The purchase and sale agreements provide that Whiting will pay Celero $343 million in cash at the August closing and $442 million in cash at the October closing, as well as issue 441,500 shares of Whiting common stock to Celero at the October closing. Based on recent trading, this stock has a value of approximately $17 million. A deposit of $80.2 million was paid on July 26, 2005, of which $80.0 million was funded with borrowings under the Credit Agreement. The effective date of both transactions will be July 1, 2005.

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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, 2004 and have not materially changed since that report was filed.

Our outstanding hedges at July 29, 2005 are summarized below:


		Monthly Volume
Commodity	Period	(MMBtu)/(Bbl)	NYMEX Floor/Ceiling
Natural Gas	07/2005 to 09/2005	1,500,000	$4.50/$8.60
Natural Gas	10/2005 to 12/2005	1,500,000	$4.50/$10.00
Natural Gas	01/2006 to 03/2006	750,000	$5.90/$10.30
Natural Gas	01/2006 to 03/2006	450,000	$6.00/$16.00
Natural Gas	01/2006 to 03/2006	300,000	$6.00/$17.00
Natural Gas	04/2006 to 06/2006	600,000	$6.00/$10.10
Natural Gas	04/2006 to 06/2006	1,000,000	$6.00/$10.12
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
Crude Oil	07/2005 to 09/2005	250,000	$35.00/$47.25
Crude Oil	08/2005 to 09/2005	110,000	$50.00/$70.95
Crude Oil	08/2005 to 09/2005	50,000	$50.00/$73.15
Crude Oil	10/2005 to 12/2005	125,000	$35.00/$60.55
Crude Oil	10/2005 to 12/2005	125,000	$35.00/$65.75
Crude Oil	10/2005 to 12/2005	110,000	$50.00/$75.00
Crude Oil	10/2005 to 12/2005	50,000	$50.00/$80.50
Crude Oil	01/2006 to 03/2006	250,000	$40.00/$51.50
Crude Oil	01/2006 to 03/2006	110,000	$50.00/$76.55
Crude Oil	01/2006 to 03/2006	50,000	$50.00/$82.25
Crude Oil	04/2006 to 06/2006	125,000	$45.00/$82.80
Crude Oil	04/2006 to 06/2006	215,000	$50.00/$73.80
Crude Oil	04/2006 to 06/2006	110,000	$50.00/$76.20
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

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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 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 2005. For the 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 $2,300,000 for 2005.

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 26, 2005 are summarized below:


		Monthly
		Volume		2005 Price
Commodity	Period	(Mmbtu)		Per Mmbtu
Natural Gas	01/2002 to 12/2011		51,000	$	4.39
Natural Gas	01/2002 to 12/2012		60,000	$	3.89

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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, as amended (the “Exchange Act”), our management evaluated, with the participation of our Chairman, President and Chief Executive Officer and our Vice President—Finance 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, 2005. Based upon their evaluation of these disclosures controls and procedures, the Chairman, President and Chief Executive Officer and the Vice President—Finance and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the end of the quarter ended June 30, 2005.

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, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

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

Whiting Petroleum Corporation held its annual meeting of stockholders on May 10, 2005. At such meeting, Kenneth R. Whiting and Palmer L. Moe were reelected as directors for terms to expire at the 2008 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
Kenneth R. Whiting	25,811,954	1,184,900
Palmer L. Moe	26,364,733	632,121

The other directors of Whiting Petroleum Corporation whose terms of office continued after the 2005 annual meeting of stockholders are as follows: terms expiring at the 2006 annual meeting: Graydon D. Hubbard and James J. Volker and terms expiring at the 2007 annual meeting: Thomas L. Aller and J. B. Ladd.

The following other matter brought for vote at the 2005 annual meeting of stockholders passed by the vote indicated:

Item 5. Other Information

Entry into a Material Definitive Agreement

Effective July 25, 2005, Whiting Petroleum Corporation and Whiting Oil and Gas Corporation entered into a Second Amendment to Second Amended and Restated Credit Agreement with the financial institutions listed therein and JP Morgan Chase Bank, N.A. as Administrative Agent (the “Amendment”). The Amendment modifies the covenant under the Second Amended and Restated Credit Agreement that limits Whiting Petroleum Corporation’s ability to hedge oil and gas prices to increase the permitted maximum time period for hedges from three to five years. A copy of the Amendment is filed herewith as Exhibit 4 and incorporated herein by reference.


	Shares Voted
	For		Against		Abstain		Broker Non-Vote
Ratification of the appointment of Deloitte & Touche LLP as independent registered public accountants		26,950,085		29,520		17,249		—

Item 6. Exhibits

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

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Item 1. Financial Statements			1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			14
Item 3. Quantitative and Qualitative Disclosures about Market Risk			27
Item 4. Controls and Procedures			29

PART II—OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders			30
Item 5. Other Information			30
Item 6. Exhibits			30
Second Amendment to Second Amended/Restated Credit Agreement
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to 18 U.S.C. Section 1350
Certification of CFO Pursuant to 18 U.S.C. Section 1350


Consolidated Balance Sheets as of June 30, 2005 (Unaudited) and December 31, 2004			2
Unaudited Consolidated Statements of Income for the Three Months and Six Months Ended June 30, 2005 and 2004			4
Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the Year Ended December 31, 2004 and the Six Months Ended June 30, 2005 (Unaudited)			5
Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2005 and 2004			6
Condensed Notes to Unaudited Consolidated Financial Statements			7


Exhibit
Number		Exhibit Description
(4)		Second Amendment to Second Amended and Restated Credit Agreement, effective as of July 25, 2005, among Whiting Oil and Gas Corporation, Whiting Petroleum Corporation and the financial institutions listed therein and JPMorgan Chase Bank, N.A., as Administrative Agent.

(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—Finance and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

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

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

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		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 — Finance and Chief Financial Officer