UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

or

Commission file number: 001-31899

WHITING PETROLEUM CORPORATION

(303) 837-1661

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 an accelerated filer (as defined in Rule 12b-2 of the Act). Yes  þ   No  o

Number of shares of the registrant’s common stock outstanding at April 15, 2005: 29,791,922 shares.

TABLE OF CONTENTS

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PART I

Item 1. Financial Statements

WHITING PETROLEUM CORPORATION
INDEX TO FINANCIAL STATEMENTS

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

See notes to unaudited consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

See notes to unaudited consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

See notes to unaudited consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

See notes to unaudited consolidated financial statements.

5

WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

See notes to unaudited consolidated financial statements.

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WHITING PETROLEUM CORPORATION AND SUBSIDIARIES

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, together with its pro rata share of the assets, liabilities, revenue and expenses of limited partnerships in which Whiting is the sole general partner. 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 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

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	Company attempts to qualify the majority of these instruments as cash flow hedges for accounting purposes.
	During the first three months of 2005 and 2004, the Company recognized losses of $2,055 and $1,015, respectively, related to its hedging activities. In addition, at March 31, 2005, Whiting’s remaining cash flow hedge positions resulted in a pre-tax liability of $27,630 of which $16,965 was recorded as a component of accumulated other comprehensive income and $10,665 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 three months ended March 31, 2005 and 2004, respectively.

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

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4.	LONG-TERM DEBT
	Long-term debt consisted of the following at March 31, 2005 and December 31, 2004:

	Credit Agreement—Whiting Oil and Gas Corporation has a $750.0 million credit agreement with a syndicate of banks that, as of March 31, 2005, had a borrowing base of $480.0 million. The borrowing base under the credit agreement is determined in the discretion of the lenders based on 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. On March 31, 2005, Whiting Oil and Gas Corporation borrowed $60.0 million in order to fund its $65.0 million acquisition of oil and natural gas producing properties located in the Green River Basin in Wyoming. As of March 31, 2005, the outstanding principal balance under the credit agreement was $215.0 million.
	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 March 31, 2005, letters of credit totaling $0.2 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 March 31, 2005, the effective weighted average interest rate on the entire outstanding principal balance of $215.0 million was fixed at 3.77% through April 29, 2005. On April 19, 2005, the Company repaid the entire outstanding principal balance of $215.0 million under the credit agreement with cash on

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	hand and proceeds from the 7 1/4% Senior Subordinated Notes due 2013. See a further discussion of this transaction in Note 9.
	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 the credit agreement provision that requires 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 our hedging to a maximum of 75% of our 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 March 31, 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 due 2012— In May 2004, the Company issued, in a private placement, $150.0 million aggregate principal amount of its 71/4% senior subordinated notes due 2012. The net proceeds of the offering were used to refinance debt outstanding under the Company’s credit agreement. 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 the Company and are subordinated to all of the Company’s senior debt. The indenture governing the notes contains various restrictive covenants that 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 payments to the Company. The Company was in compliance with these covenants as of March 31, 2005. 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. All of the Company’s subsidiaries other than the Guarantors are minor within the meaning of Rule 3-10(h)(6) of Regulation

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	S-X of the Securities and Exchange Commission, and the Company has no independent assets or operations. Based on the market price of the 7 1/4 % Senior Subordinated Notes due 2012, their estimated fair value was $151.9 million as of March 31, 2005.
	Interest Rate Swap—In August 2004, the Company entered into an interest rate swap contract to hedge the fair value of $75 million of our 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 we receive the fixed rate of 7.25% and pay 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 our margin of 2.345% is less than 7.25%, we receive a payment from the counterparty equal to the difference in rate times $75 million for the six month period. When LIBOR plus our margin of 2.345% is greater than 7.25%, we pay the counterparty an amount equal to the difference in rate times $75 million for the six month period. The LIBOR rate at March 31, 2005 was 2.3%. As of March 31, 2005, we have recorded a long term derivative asset of $0.3 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.
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 three months of 2005, the Company granted 85,732 shares of restricted stock under this plan and 6,865 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

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	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 million. The Company has estimated total payments to Alliant will approximate $49 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.
	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 three months of 2005, the Company did not make any payments under this agreement but did recognize $0.62 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 $4,214 is reflected as a current liability at March 31, 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, management has assumed that no such change will occur during the term of this agreement.

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8.	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.
9.	SUBSEQUENT EVENT
	On April 19, 2005, the Company issued, in a public offering, $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 refinance debt outstanding under Whiting Oil and Gas Corporation’s credit agreement. The notes are unsecured obligations of the Company and are subordinated to all of the Company’s senior debt. 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. The indenture governing the notes contains restrictive covenants that are substantially identical to those contained in the indenture governing the Company’s 7 1/4% Senior Subordinated Notes due 2012. 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 payments to the Company. Three of the Company’s subsidiaries, Whiting Oil and Gas Corporation, Equity Oil Company and Whiting Programs, Inc. (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.

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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; 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

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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 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.

We completed seven separate acquisitions of producing properties during 2004. The combined purchase price for these seven acquisitions was $535.1 million for total estimated proved reserves as of the effective dates of the acquisitions of approximately 436.1 Bcfe. We also completed the Green River Basin acquisition on March 31, 2005 for $65.0 million. See “Green River Basin” below. Because the Green River Basin acquisition was closed on the last day of the first quarter of 2005, it did not affect operating results. 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

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004

Selected Operating Data:

          Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased approximately $57.8 million to $105.5 million in the first quarter of 2005 compared to the first quarter of 2004. Sales are a function of sales volumes and average sales prices. Our sales volumes increased 73.3% 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 offset by temporary pipeline shutdowns for repairs by a gas purchaser in South Texas as well as workover activity in the Big Stick Field in North Dakota. Our average price for natural gas sales increased 7.6% and our average price for crude oil increased 43.8% between periods.

          Loss on Oil and Natural Gas Hedging Activities. We hedged 60% of our natural gas volumes during the first quarter of 2005 and 46% of our natural gas volumes during the first quarter of 2004 incurring no hedging loss or gain in either period. We hedged 70% of our oil volumes during the first quarter of 2005 incurring a hedging loss of $2.1 million, and 46.0% of our oil volumes during the first quarter of 2004 incurring a loss of $1.0 million. See Item 3, “Qualitative and Quantitative Disclosures About Market Risk” for a list of our outstanding oil and natural gas hedges as of April 15, 2005.

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          Lease Operating Expenses. Our lease operating expense increased approximately $10.3 million to $20.8 million in the first quarter of 2005 compared to the first 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 22.1% during the first quarter of 2004 to 19.8% during the first quarter of 2005 as lease operating costs increases did not keep pace with sales price increases. Our lease operating expenses per Mcfe increased from $1.12 during the first quarter of 2004 to $1.28 during the first quarter of 2005. The increase of 14.3% 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 first quarters of 2005 and 2004 were 6.2% and 6.3% of oil and natural gas sales, respectively.

          Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $9.6 million to $20.3 million during the first quarter of 2005 compared to $10.7 million for the first quarter of 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 $1.25 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. 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):

          Exploration. Our exploration costs increased $1.0 million to $1.4 million in the first quarter of 2005 compared to the first quarter of 2004. The higher exploratory costs resulted from 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.

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

          General and administrative expense before reimbursements increased $4.0 million to $9.3 million during the first quarter of 2005 compared to $5.3 million during the first quarter of 2004. The largest components of the increase related to costs associated with our production participation plan of $1.9 million and increased salaries of $1.4 million. The increased cost of the production participation plan was caused primarily by increased production and increased average prices between the first 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 2004. Our general and administrative expense decreased between periods from $0.43 to $0.41 per Mcfe. As a percentage of oil and gas sales, our general and administrative expense also decreased from 8.4% during the first quarter of 2004 to 6.4% during the first quarter of 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:

          The increase in interest expense was primarily due to the May 2004 issuance of $150.0 million of 7¹/4% Senior Subordinated Notes due 2012. In August of 2004, $75.0 million of the face amount of the notes was swapped to a floating rate. At December 31, 2004, the floating rate component was set at 4.645% through May 1, 2005, yielding a first quarter 2005 weighted average effective interest rate on the $150.0 million issuance of 5.95%. We expect the floating rate component to increase approximately 1% at May 1, 2005 due to increases in interest rates since November 1, 2004.

          Interest expense on our credit agreement in the first quarter of 2005 was $418,000 higher than first quarter of 2004. This was primarily the result of higher weighted average effective cash interest rates of 4.25% in the first quarter of 2005 compared to 3.4% in the first quarter of 2004.

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          The accretion of our tax sharing liability is related to a step-up in tax basis effected immediately prior to our initial public offering in November 2003. The increase in debt issue and debt discount amortization was due to the amortization of additional fees incurred after the first quarter of 2004 to refinance our credit agreement and issue $150.0 million of our 7¹/4% Senior Subordinated Notes due 2012.

          Income Tax Expense. Income tax expense totaled $16.4 million for the first quarter of 2005 and $6.1 million for the first quarter of 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 quarter of 2005, we estimate that our full year 2005 cash tax liability would approximate 10% of the full year 2005 tax provision and have reflected this as current tax expense.

          Net Income. Net income increased from $9.6 million during the first quarter of 2004 to $26.1 million during the first quarter of 2005. The primary reasons for this increase included 28.1% higher crude oil and natural gas prices net of hedging between periods and a 73.3% increase in equivalent volumes sold, offset by higher lease operating expense, general and administrative, DD&A, interest and exploration and impairment costs in the first 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 quarter of 2005, we generated an additional $69.0 million from operating activities and $40.0 million from financing activities. We used these sources of cash in the first quarter of 2005 to finance cash acquisitions of $68.6 million and drilling capital expenditures of $25.7 million. At March 31, 2005, our debt to total capitalization ratio was 37.1%, we had $16.3 million of cash on hand and $622.7 million of stockholders’ equity.

          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 $25.7 million in the first quarter. 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 $68.6 million on acquisitions in the first quarter 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

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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 March 31, 2005, provided a borrowing base of $480.0 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. During the first quarter of 2005, we repaid $20.0 million under the credit agreement from operating cash flows and borrowed $60.0 million to fund the Green River Basin property acquisition. As of March 31, 2005, the outstanding principal balance under the credit agreement was $215.0 million. 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.

          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 March 31, 2005, letters of credit totaling $0.2 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.

          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 PDP production for the period 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 March 31, 2005. The credit agreement is secured by a first lien on

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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 due 2012. In May 2004, we issued, in a private placement, $150.0 million aggregate principal amount of our 7 1/4% senior subordinated notes due 2012. The net proceeds of the offering were used to retire all of our debt outstanding under Whiting Oil and Gas Corporation’s credit agreement. 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 indenture governing the notes contains 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 limit the discretion of our management in operating our business. We were in compliance with these covenants as of December 31, 2004. 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.

     7 ¹/4% Senior Subordinated Notes due 2013. On April 19, 2005, we issued, in a public offering, $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 refinance debt outstanding under Whiting Oil and Gas Corporation’s credit agreement. The notes are unsecured obligations of ours and are subordinated to all of our senior debt. 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. The indenture governing the notes contains restrictive covenants that are substantially identical to those contained in the indenture governing the Company’s 7 ¹/4% Senior Subordinated Notes due 2012. These covenants may limit the discretion of our management in operating our business. Three of our subsidiaries, Whiting Oil and Gas Corporation, Equity Oil Company and Whiting Programs, Inc., 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

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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 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 quarter of 2005, we did not make any payments under this agreement but did recognize $2.4 million and $620,000, 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 March 31, 2005.

          Schedule of Contractual Obligations. The following table summarizes our obligations and commitments as of March 31, 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.

          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 March 31, 2005, approximately 37,700 net barrels of crude oil per month (7.4% of March 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 quarter of 2005, we paid $1.5 million under this agreement. As of March 31, 2005, we have accrued an additional $473,000 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 three months ended March 31, 2005.

Effects of Inflation and Pricing

          We experienced increased costs during 2004 and the first quarter 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.

Green River Basin Acquisition

          On March 31, 2005, we completed our acquisition of 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. We operate approximately 95% of the net daily production from the properties, which was estimated at 6.3 MMcfe per day at the acquisition date. We funded the acquisition through borrowings under Whiting Oil and Gas Corporation’s credit agreement and cash on hand.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

          Hedging – 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 as of April 15, 2005 are summarized below:

          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 $450,000 for 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 $750,000 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 April 15, 2005 are summarized below:

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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 (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 March 31, 2005. 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 March 31, 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 March 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 6. Exhibits

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

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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 25^th day of April, 2005.

	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

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EXHIBIT INDEX

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