WHITING PETROLEUM CORP - 10-Q Quarterly Report

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 x No ¨

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

Number of shares of the registrant’s common stock outstanding at October 15, 2004: 21,100,347 shares.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME FOR THE YEAR ENDED DECEMBER 31, 2003 AND THE NINE MONTHS ENDED SEPTEMBER 30, 2004 (Unaudited)

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004 AND 2003

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. Just prior to the initial public offering of Whiting’s common stock, the Company in effect split its common stock, issuing 18,330 shares for the 1 previously held by Alliant Energy. All periods presented have been adjusted to reflect the current capital structure. Whiting acquires, develops and explores for producing oil and gas properties primarily in the Gulf Coast/Permian Basin, Rocky Mountains, Michigan, and Mid-Continent 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 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, 2003. 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 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 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.

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 nine months of 2004 and 2003, the Company recognized losses of $3,615 and $8,953, respectively, related to its hedging activities. In addition, at September 30, 2004, Whiting’s remaining cash flow hedge positions resulted in a pre-tax liability of $9,850 of which $6,050 was recorded as a component of accumulated other comprehensive income and $3,000 was recorded as a decrease to the deferred tax liability. See Note 5 for restrictions in our credit agreement relating to hedging activities.

As of December 31, 2003, the Company held an investment in a publicly traded security classified as available-for-sale (included in other long term-assets). The original cost to the Company was $585. During the nine months ended September 30, 2004, the Company sold its holdings for $5,420 realizing a gain on sale of $4,835. As of December 31, 2003, the Company recorded an unrealized holding gain of $1,782 of which $1,094 was recorded as a component of accumulated other comprehensive income and $688 was recorded as a decrease to the deferred tax asset.

Effective January 1, 2003, the Company adopted the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires the Company to recognize the fair value of asset retirement obligations in the financial statements by capitalizing that cost as a part of the cost of the related asset. In regards to the Company, this Statement applies directly to the plug and abandonment liabilities associated with the Company’s net working interest in well bores. 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 the discount 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 Company’s estimated liability for plugging and abandoning its oil and natural gas wells and certain obligations for onshore and offshore facilities in California is discounted using a credit-adjusted risk-free rate of approximately 7%. Upon adoption of SFAS No. 143, the Company recorded an increase to its discounted asset retirement obligations of $16.4 million, increased proved property cost by $10.1 million and recognized a one-time cumulative effect charge of $3.9 million (net of a deferred tax benefit of $2.4 million).

The following table provides a reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2004 and the year ended December 31, 2003.

No revisions have been made to the timing or the amount of the original estimate of undiscounted cash flows during 2003 or the first nine months of 2004.

Long-term debt consisted of the following at September 30, 2004 and December 31, 2003:

Credit Facility—On September 23, 2004, Whiting Oil and Gas Corporation entered into an amended and restated $750.0 million credit agreement with a syndicate of banks. The new credit agreement increases the Company’s borrowing base to $480.0 million from $195.0 million under the prior credit agreement. 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 September 23, 2004, Whiting Oil and Gas Corporation borrowed $400.0 million under the credit agreement in order to (i) refinance the entire outstanding balance under the prior credit agreement and (ii) fund its $345.0 million acquisition of oil and natural gas producing properties from CrownQuest Operating LLC. On September 30, 2004, an additional $35.0 million was borrowed to fund an additional acquisition.

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. 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.

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 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. The credit agreement also requires the Company to hedge at least 60% but not more than 75% of its total forecasted proved developed producing 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 million British Thermal Units (MMBtu). 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 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 September 30, 2004. 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.

7¼% Senior Subordinated Notes due 2012— On May 11, 2004, the Company issued, in a private placement, $150.0 million aggregate principal amount of its 7¼% 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. On July 12, 2004, the Company completed an exchange offer in which it issued $150.0 million aggregate principal amount of new 7¼% senior subordinated notes due 2012 registered under the Securities Act of 1933 in exchange for the old 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 September 30, 2004. 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 S-X of the Securities and Exchange Commission, and the Company has no independent assets or operations.

Interest Rate Swap—In August 2004, we entered into an interest rate swap contract to hedge the fair value of $75 million of our 7¹/4% 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. As of September 30, 2004, we have recorded a long term derivative asset of $1.7 million related to the interest rate swap, which has been designated as a fair value hedge, with a corresponding debt increase.

Long-Term Debt Payable to Alliant Energy—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.

Alliant Energy had loaned the Company an aggregate $80.5 million as of December 31, 2002. The note bore interest at a floating rate which ranged from 6.9% to 4.4% during the first quarter of 2003. On March 31, 2003, Alliant Energy converted its outstanding intercompany balance of $80.9 million to equity of the Company.

The Company’s Board of Directors adopted the Whiting Petroleum Corporation 2003 Equity Incentive Plan on September 17, 2003. Two million shares of the Company’s common stock have been reserved for issuance under this plan. 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 quarters of 2004, the Company granted 112,921 shares of restricted stock under this plan. The shares of restricted stock were recorded at fair value of $2.5 million and are being amortized to general and administrative expense over their three year vesting period.

The Company maintains 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 and plan participants generally vest ratably over five years. Forfeitures are re-allocated among other Plan participants. Allocations prior to 1995 consisted of 2% - 3% overriding royalty interests. Allocations since 1995 have been 2% - 5% net revenue interests. Payments to participants of the plan are made annually in cash after year end.

Effective April 23, 2004, the Production Participation Plan was amended and restated. Specifically, the plan was amended to (1) provide that, 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) provide that employees will become fully vested at age 65, regardless of when their interests would otherwise vest; and (3) provide that, for pools for years 2004 and beyond, if there are forfeitures, the interests will inure to the benefit of the Company.

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 nine months of 2004, the Company recognized $1.8 million of accretion expense which is included as a component of interest expense.

There is a provision in the Tax Separation Agreement 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.

On September 23, 2004, we acquired interests in seventeen fields in the Permian Basin of West Texas and Southeast New Mexico, including interests in key fields such as Parkway Field in Eddy County, New Mexico; Would Have and Signal Peak Fields in Howard County, Texas; Keystone Field in Winkler County, Texas; and the DEB Field in Gaines County, Texas. The purchase price was $345.0 million in cash and was funded through borrowings under our bank credit agreement.

For the year ended December 31, 2003, these properties reported revenues in excess of direct operating expenses of $72.1 million. As of October 1, 2004, these properties had 250.0 Bcfe of estimated proved reserves, of which 17.8% were natural gas and 58.9% were classified as proved developed, and had a pre-tax PV10 value of estimated proved reserves of $673.6 million. The estimated October 2004 average daily production for these properties is approximately 36.4 MMcfe, implying an average reserve life of 18.8 years. We operate approximately 72% of the average daily production from these properties.

We acquired 100% of the outstanding stock of Equity Oil Company on July 20, 2004. In the merger, we issued approximately 2.2 million shares of our common stock to Equity’s shareholders and repaid all of Equity’s outstanding debt of $29.0 million under its credit facility. Equity’s operations are focused primarily in California, Colorado, North Dakota and Wyoming.

For the year ended December 31, 2003, Equity reported income from continuing operations of $2.4 million, net cash provided by operating activities of $11.5 million and production of 6.6 Bcfe (45% natural gas). As of October 1, 2004, Equity had 92.4 Bcfe of estimated proved reserves, of which 29.7% were natural gas and 81.4% were classified as proved developed, and had a pre-tax PV10% value of estimated proved reserves of approximately $242.1 million. The estimated October 2004 average daily production from these properties is approximately 16.1 MMcfe, implying an average reserve life of 15.7 years.

Based on the purchase price of $72.6 million and estimated proved reserves of 87.7 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $0.83 per Mcfe of estimated proved reserves.

On August 13, 2004, we acquired interests in four producing oil and gas fields in Colorado and Wyoming from an undisclosed seller. The purchase price was $44.2 million in cash and was funded under our bank credit agreement. We operate two of the fields and have an 84% average working interest in those fields. As of October 1, 2004, these interests had 40.0 Bcfe of estimated proved reserves and estimated October 2004 average daily production of 8.6 MMcfe, implying an average reserve life of 12.7 years. Based on the purchase price of $44.2 million and estimated proved reserves of 39.8 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.11 per Mcfe of estimated proved reserves.

On September 30, 2004, we acquired interests in three operated fields in Wyoming and Utah from an undisclosed seller. The purchase price was $35.0 million in cash and was funded under our bank credit agreement. As of October 1, 2004, these interests had 32.6 Bcfe of estimated proved reserves and estimated October 2004 average daily production of 6.1 MMcfe, implying an average reserve life of 14.6 years. Based on the purchase price of $35.0 million and estimated proved reserves of 30.8 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.14 per Mcfe of estimated proved reserves.

On August 16, 2004, we acquired interests in five fields in Louisiana and South Texas from Delta Petroleum Corporation. The purchase price was $19.3 million in cash and was funded under our bank credit agreement. We operate two of the fields and have a 93% average working interest in those fields. As of October 1, 2004, these interests had 13.9 Bcfe of estimated proved reserves and estimated October 2004 average daily production of 3.5 MMcfe, implying an average reserve life of 11.0 years. Based on the purchase price of $19.3 million and estimated proved reserves of 12.0 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.61 per Mcfe of estimated proved reserves.

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

The following table reflects the unaudited pro forma results of operations for the year ended December 31, 2003 and for the three and nine month periods ended September 30, 2004 as though the above acquisitions had occurred on the first day of each period presented. The pro forma amounts for the three and nine month periods ended September 30, 2004 include only the activity from the beginning of the period to the closing date of the acquisitions. (in thousands, except per share amounts):

The following is a summary of the unaudited financial data for each quarter for the nine months ended September 30, 2004 (in thousands, except per share data):

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 only operating subsidiary, Whiting Oil and Gas Corporation. When the context requires, we refer to these entities separately.

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.

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. During periods of radically changing prices, we focus our emphasis on drilling and development of our owned properties. When prices stabilize, we generally direct the majority of our capital to acquisitions.

We have historically acquired operated as well as non operated properties that meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, our focus has been on acquiring operated properties so that we can better control the timing and implementation of capital spending. In some instances, we have been able to acquire non operated property interests at attractive rates of return that provided a foothold in a new area of interest or 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 five separate acquisitions of producing properties during the first nine months of 2004. The combined purchase price for these five acquisitions was $516.1 million for total estimated proved reserves as of the effective dates of the acquisitions of approximately 421.9 Bcfe. For more information on these acquisitions, see “—Recent Acquisitions” below. Because of our substantial recent acquisition activity, our discussion and analysis of our historical financial condition and results of operations for the periods discussed below may not necessarily be comparable with or applicable to our future results of operations. Our historical results include the results from our recent acquisitions beginning on the following dates: Permian Basin, September 23, 2004; Equity Oil Company, July 20, 2004; Colorado and Wyoming, August 13, 2004; and Louisiana and Texas, August 16, 2004. Our historical results do not include results from our Wyoming and Utah acquisition that closed on September 30, 2004, but our balance sheet information as of September 30, 2004 does include the effect of such acquisition.

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.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003

Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased approximately $32.8 million to $166.4 million for the first nine months of 2004. Sales are a function of sales volumes and average sales prices. Our sales volumes increased 8.6% between periods on a Mcfe basis. The volume increase resulted from successful drilling and acquisition activities over the past year that produced new sales volumes that more than offset natural decline. Our average price for natural gas sales increased 6.4% and our average price for crude oil increased 26.8% between periods.

Loss on Oil and Natural Gas Hedging Activities. We hedged 22% of our natural gas volumes during the first nine months of 2004 incurring no hedging loss or gain, and 42% of our natural gas volumes during the same period of 2003 incurring a hedging loss of $8.0 million. We hedged 42% of our oil volumes during the first nine months of 2004 incurring a hedging loss of $3.6 million, and 11% of our oil volumes during the same period of 2003 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 October 14, 2004.

Gain on Sale of Marketable Securities. During the initial nine months of 2004, we sold all of our holdings in Delta Petroleum, Inc., which trades publicly under the symbol “DPTR”. We realized gross proceeds of $5.4 million and recognized a gain on sale of $4.8 million. At September 30, 2004, we had no investments in marketable securities.

Gain on Sale of Oil and Gas Properties. During the third quarter of 2004, we sold certain undeveloped acreage held by production in Wyoming. No value had been assigned to the acreage when we acquired it over five years ago. As a result, the recognized gain on sale is equal to the gross proceeds of $1.0 million.

Lease Operating Expenses. Our lease operating expenses per Mcfe decreased from $1.16 during the first nine months of 2003 to $1.15 during the same period in 2004. The decrease was less than 1%, which represented improved operating efficiency more than offsetting 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% and 6.5% of oil and natural gas sales revenue. Our production taxes for the initial nine months of 2004 and 2003 were 6.1% of oil and natural gas sales.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $3.8 million to $34.5 million for the first nine months of 2004. The increase resulted from increased production and an increase in the DD&A rate. On a Mcfe basis, the rate increased from $1.11 during the first nine months of 2003 to $1.15 during the same period in 2004. We expect our DD&A rate to increase in the fourth quarter due to the effects of the recent acquisitions. 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 depreciation, depletion and amortization expense were as follows (in thousands):

Exploration and Impairment Costs. Our exploration and impairment costs increased $3.7 million to $4.7 million for the first nine months of 2004. The higher exploratory costs were related to our increased purchases of seismic in 2004 to support our increased drilling budget. The impairment charge represents the write down of cost associated with the High Island field located off the coast of Texas.

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 $4.2 million to $18.0 million during the first nine months of 2004. On a Mcfe basis, the increase between nine month periods was from $0.34 to $0.47. The largest component of the increase related to costs associated with our production payment plan. During periods of increased acquisition activity, our general and administrative expense will be higher because we must immediately recognize the discounted value of estimated plan payments to employees 65 and older. The discounted value of estimated payments to employees under 65 is generally amortized over a five year vesting period. Costs related to the production payment plan increased $1.8 million between nine month periods. The remaining increase was primarily caused by the extra costs of functioning as a public company, increases in the employee base due to our continued growth and general cost inflation. The decrease in reimbursements was caused by our purchase of the limited partnership interests in three of the six remaining managed partnerships during the second quarter of 2003. We expect our general and administrative expense to decrease to under $0.38 per Mcfe sold in the fourth quarter due to cost synergies from recent acquisitions.

The decrease in bank interest was primarily due to our $40.0 million pay down of our credit facility on February 17, 2004 and our repayment of the remaining principal balance outstanding under the credit facility on May 11, 2004 with the proceeds from the issuance of our 7¼% Senior Subordinated Notes due 2012. We expect our overall interest expense to increase during the remainder of 2004 due to the cash acquisitions closed during the third quarter of 2004,

which increased the outstanding balance under our credit facility to $435 million as of September 30, 2004. In addition, in August, we entered into an interest rate swap causing the interest rate on $75 million of the 7¼% Senior Subordinated Notes due 2012 to change from a 7.25% fixed rate to a floating rate. The effect of the swap was to lower our overall effective interest rate on this debt from 7.25% to approximately 5.6% through November 1, 2004. On November 1, 2004 and every six months thereafter, the floating rate component will be locked in for six month periods at the then in effect six month London Interbank Offered Rate, or LIBOR, rate plus a margin of 2.345%. The decrease in interest expense related to Alliant was due to the March 31, 2003 conversion of $80.9 million of intercompany debt into our equity. The accretion of our tax sharing liability is related to a step-up in tax basis effected immediately prior to our initial public offering (“IPO”) in November 2003. A further explanation of the step-up transaction is included in the “Liquidity and Capital Resources” section below.

Income Tax Expense. We estimate that our effective income tax rate was 38.6% during the initial nine months of 2004, consistent with the yearly estimated effective tax rate for 2003. Prior to our IPO, we were included in the consolidated federal income tax return of Alliant Energy and calculated our income tax expense on a separate return basis at Alliant Energy’s effective income tax rate. Immediately prior to our IPO, Alliant Energy effected a step-up in the tax basis of Whiting Oil and Gas Corporation’s assets, which had the result of increasing our future tax deductions. As a result of this step-up in tax basis and the net operating loss generated during the post-IPO stub period in 2003, we currently expect to pay only a small amount of income taxes related to the 2004 tax year.

Cumulative Change in Accounting Principle. Effective January 1, 2003, we adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” This statement generally applies to legal obligations associated with the retirement of long-lived assets and requires us to recognize the fair value of asset retirement obligations in our financial statements by capitalizing that cost as a part of the cost of the related asset. This statement applies directly to plug and abandonment liabilities associated with our net working interest in well bores. The additional carrying amount is depleted over the estimated useful lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and the discount is accreted at the end of each accounting period through charges to D,D&A. Upon adoption of SFAS No. 143, we recorded an increase to our discounted asset retirement obligations of $16.4 million, increased proved property cost by $10.1 million and recognized a one-time cumulative effect charge of $3.9 million (net of a deferred tax benefit of $2.4 million).

Net Income. Net income increased from $18.6 million during the initial nine months of 2003 to $37.4 million during the same period in 2004. The primary reasons for this increase included 20% higher crude oil and natural gas prices net of hedging between periods, 8.6% increase in equivalent volumes sold, the impact of the cumulative effect of adoption of SFAS No. 143 in 2003, the impact of property and marketable security sales in 2004, offset by higher lease operating expense, general and administrative, DD&A, interest and exploration and impairment costs in 2004.

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003

Oil and Natural Gas Sales. Our oil and natural gas sales revenue increased approximately $23.6 million to $65.9 million for the third quarter of 2004. Sales are a function of sales volumes and average sales prices. Our sales volumes increased 21.4% between periods on a Mcfe basis. The volume increase resulted from successful drilling and acquisition activities over the past year which produced new sales volumes that more than offset natural decline. Our average price for natural gas sales increased 15.3% and our average price for crude oil increased 44.3% between periods.

Loss on Oil and Natural Gas Hedging Activities. We hedged 19.6% of our natural gas volumes during the third quarter of 2004 but did not incur any hedging gain or loss. During the third quarter of 2003 we hedged 39.3% of our natural gas volumes incurring a hedging loss of $0.1 million. We hedged 35% of our oil volumes during the third quarter of 2004 incurring a hedging loss of $2.1 million, and 2.5% of our oil volumes during the same period of 2003 incurring a loss of $0.1 million. See Item 3, “Qualitative and Quantitative Disclosures About Market Risk” for a list of currently outstanding oil and natural gas hedges.

Gain on Sale of Marketable Securities. During the third quarter, we sold all of our remaining shares of Delta Petroleum, Inc., which trades publicly under the symbol “DPTR”. We realized gross proceeds of $2.7 million and recognized a gain on sale of $2.4 million. At September 30, 2004, we had no investments in marketable securities.

Lease Operating Expenses. Our lease operating expenses per Mcfe decreased from $1.22 during the third quarter of 2003 to $1.15 during the same period in 2004. The rate for the third quarter of 2003 rate was higher due to a large number of workover operations performed in the quarter. The current quarter rate of $1.15 per Mcfe is consistent with the 2003 full year rate of $1.16 per Mcfe.

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% and 6.5% of oil and natural gas sales revenue. Our production taxes for the third quarters of 2004 and 2003 were 6.0% and 6.1%, respectively, of oil and natural gas sales.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense (“DD&A”) increased $2.8 million during the third quarter of 2004 compared to the third quarter of 2003. The increase resulted from increased production and an increase in the DD&A rate. On a Mcfe basis, the rate increased from $1.10 during the third quarter of 2003 to $1.15 during the same period in 2004. Our DD&A rate increased between periods because capital costs incurred were proportionally higher than new reserves added. We expect our DD&A rate to increase in the fourth quarter due to the effects of recent acquisitions. Future changes in the pricing environment could significantly 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 depreciation, depletion and amortization expense were as follows (in thousands):

Exploration and Impairment Costs. Our exploration and impairment costs increased $3.5 million to $3.8 million for the third quarter of 2004. The higher exploratory costs were related to our increased purchases of seismic in 2004 to support our increased drilling budget. The impairment charge represents the write down of cost associated with the High Island field located off the coast of Texas.

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 increased $3.0 million to $6.1 million during the second quarter of 2004. The largest component of the increase related to costs associated with our production payment plan. During periods of increased acquisition activity, our general and administrative expense will be higher because we must immediately recognize the discounted value of estimated plan payments to employees 65 and older. The discounted value of estimated payments to employees under 65 is generally amortized over a five year vesting period. Costs related to the production payment plan increased $1.9 million between three month periods. The remaining increase was primarily caused by the extra costs of functioning as a public company, increases in the employee base due to our continued growth and general cost inflation. We expect our general and administrative expense to decrease from $0.54 per Mcfe in the third quarter to under $0.38 per Mcfe sold in the fourth quarter due to cost synergies from recent acquisitions. Reimbursements are consistent between three month periods and should increase in the fourth quarter of 2004 due to the increase in our operated well count associated with recent acquisitions.

The decrease in bank interest was primarily due to a reduction in the amount of average outstanding borrowings and lower average interest rate during the third quarter of 2004 compared to 2003. We entered the third quarter of 2004 with no bank debt due to a $40.0 million pay down of our credit facility on February 17, 2004 and our repayment of the remaining principal

balance outstanding under the credit facility on May 11, 2004 with the proceeds from the issuance of our 7¹/4% Senior Subordinated Notes due 2012. We had $185 million outstanding during the entire 2003 third quarter. We expect our overall interest expense to increase during the remainder of 2004 due to the cash acquisitions closed during the third quarter of 2004, which increased the outstanding balance under our credit facility to $435 million as of September 30, 2004. In addition, in August, we entered into an interest rate swap causing the interest rate on $75 million of the 7¹/4% Senior Subordinated Notes due 2012 to change from a 7.25% fixed rate to a floating rate. The effect of the swap was to lower our overall effective interest rate on this debt from 7.25% to approximately 5.6% through November 1, 2004. On November 1, 2004 and every six months thereafter, the floating rate component will be locked in for six month periods at the then in effect six month LIBOR rate plus a margin of 2.345%. The accretion of our tax sharing liability is related to a step-up in tax basis effected immediately prior to our initial public offering (“IPO”) in November 2003. A further explanation of the step-up transaction is included in the “Liquidity and Capital Resources” section below.

Income Tax Expense. We estimate our effective income tax rate at 38.6% during the third quarter of 2004 and 38% during the third quarter of 2003. Prior to our IPO, we were included in the consolidated federal income tax return of Alliant Energy and calculated our income tax expense on a separate return basis at Alliant Energy’s effective income tax rate. Immediately prior to our IPO, Alliant Energy effected a step-up in the tax basis of Whiting Oil and Gas Corporation’s assets, which had the result of increasing our future tax deductions. As a result of this step-up in tax basis and the net operating loss generated during the post-IPO stub period in 2003, we currently expect to only a small amount of income taxes related to the 2004 tax year.

Net Income. Net income increased from $8.0 million during the third quarter of 2003 to $14.3 million during the third quarter of 2004. The primary reasons for this increase included 24.9% higher crude oil and natural gas prices net of hedging between periods, 21.4% increase in volumes sold, the impact of property and marketable security sales in the third quarter of 2004, offset by higher lease operating expense, general and administrative, DD&A, interest and exploration and impairment costs in 2004 due to the growth of our company.

Overview. We entered 2004 with $53.6 million of cash and cash equivalents. During the first nine months of 2004, we generated an additional $96.9 million from operating activities. On February 17, 2004, we used $40.0 million of our cash to pay down $40.0 million of the outstanding principal balance under our bank credit facility. On May 11, 2004, we used the proceeds from the issuance of our 7¹/4% Senior Subordinated Notes due 2012 to repay the remaining $145 million of outstanding principal under our credit facility. At September 30, 2004, our debt to total capitalization ratio was 63.7%, we had $17.4 million of cash on hand and $334.9 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 $80.0 million during 2004, an increase from the $48.6 million spent on capitalized development during 2003. During the first nine months of 2004, we spent $52.8 million on development, which was an 102% increase from the $26.2 million spent on development during the first nine months of 2003. We also spent $445.3 million on acquisitions, funded primarily by borrowings under our credit facility, all in the third quarter of 2004. 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 the remainder of our 2004 development expenditures from internally generated cash flow and cash on hand. We believe that should attractive acquisition opportunities arise or development expenditures exceed $80.0 million, we could finance the additional capital expenditures with cash on hand, operating cash flow, borrowings under Whiting Oil and Gas Corporation’s credit agreement, issuances of additional equity 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 Facility. On September 23, 2004, Whiting Oil and Gas Corporation entered into an amended and restated $750.0 million credit agreement with a syndicate of banks. The new credit agreement increases our borrowing base to $480.0 million from $195.0 million under the prior credit agreement. 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 September 23, 2004, Whiting Oil and Gas Corporation borrowed $400.0 million under the credit agreement in order to (i) refinance the entire outstanding balance under the prior credit agreement and (ii) fund its $345.0 million acquisition of oil and natural gas producing properties from CrownQuest Operating LLC. On September 30, 2004, an additional $35.0 million was borrowed to fund an additional acquisition.

The credit agreement provides for interest only payments until September 23, 2008, when the entire amount borrowed is due. In addition, the credit agreement provides that Whiting Oil and Gas Corporation will make principal payments under the credit agreement by May 1, 2005 to reduce the principal balance to $385.0 million. 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. 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, enter into hedging contracts, 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. The credit agreement also requires us to hedge at least 60% but not more than 75% of our total forecasted proved developed producing 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 million British Thermal Units (MMBtu). 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 September 30, 2004. 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.

7¹/4% Senior Subordinated Notes due 2012. On May 11, 2004, we issued, in a private placement, $150.0 million aggregate principal amount of our 7¹/4% 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. On July 12, 2004, we completed an exchange offer in which we issued $150.0 million aggregate principal amount of new 7¹/4% senior subordinated notes due 2012 registered under the Securities Act of 1933 in exchange for the old 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 us 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 September 30, 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.

Alliant Energy Promissory Note. In conjunction with our initial public offering in November 2003, we issued a promissory note payable to Alliant Energy 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 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.

Schedule of Contractual Obligations. The following table summarizes our obligations and commitments as of September 30, 2004 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 7¹/4% senior subordinated notes due 2012. The amount of interest we expect to pay relating to the $75.0 million of our senior subordinated notes remaining under the 7¹/4% fixed rate is $1.4 million during the last three months of 2004, then $5.4 million annually through the term of the notes.

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, 2003. No material changes to such information have occurred during the nine months ended September 30, 2004.

We experienced increased costs during 2003 and 2004 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. 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.

Colorado and Wyoming Properties. On August 13, 2004, we acquired interests in four producing oil and gas fields in Colorado and Wyoming from an undisclosed seller. The purchase price was $44.2 million in cash and was funded under our bank credit agreement. We operate two of the fields and have an 84% average working interest in those fields. As of October 1, 2004, these interests had 40.0 Bcfe of estimated proved reserves and estimated October 2004 average daily production of 8.6 MMcfe, implying an average reserve life of 12.7 years. Based on the purchase price of $44.2 million and estimated proved reserves of 39.8 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.11 per Mcfe of estimated proved reserves.

Wyoming and Utah Properties. On September 30, 2004, we acquired interests in three operated fields in Wyoming and Utah from an undisclosed seller. The purchase price was $35.0 million in cash and was funded under our bank credit agreement. As of October 1, 2004, these interests had 32.6 Bcfe of estimated proved reserves and estimated October 2004 average daily production of 6.1 MMcfe, implying an average reserve life of 14.6 years. Based on the purchase price of $35.0 million and estimated proved reserves of 30.8 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.14 per Mcfe of estimated proved reserves.

Louisiana and South Texas Properties. On August 16, 2004, we acquired interests in five fields in Louisiana and South Texas from Delta Petroleum Corporation. The purchase price was $19.3 million in cash and was funded under our bank credit agreement. We operate two of the fields and have a 93% average working interest in those fields. As of October 1, 2004, these interests had 13.9 Bcfe of estimated proved reserves and estimated October 2004 average daily production of 3.5 MMcfe, implying an average reserve life of 11.0 years. Based on the purchase price of $19.3 million and estimated proved reserves of 12.0 Bcfe on the effective date of the acquisition, we acquired these properties for approximately $1.61 per Mcfe of estimated proved reserves.

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, 2003 and have not materially changed since that report was filed.

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 $145,000 for the remainder of 2004. 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 $314,000 for the remainder of 2004.

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 October 14, 2004 are summarized below:

The table below summarizes the hedges and fixed price marketing contracts described above:

Market risk is estimated as the change in fair value resulting from a hypothetical 100 basis point change in the interest rate on the outstanding balance under our credit facility. The credit facility allows us to fix the interest rate for all or a portion of the principal balance for a period up to six months. To the extent the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of the credit facility that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. At September 30, 2004, our outstanding principal balance under our credit facility was $435.0 million and the interest rate on the entire outstanding principal balance was fixed at 3.34% through October 28, 2005. At September 30, 2004, the carrying amount approximated fair market value. Assuming a constant debt level of $588.8 million, the cash flow impact for 2004 resulting from a 100 basis point change in interest rates during periods when the interest rate is not fixed would be $907,000.

In August 2004, we entered into an interest rate swap contract to hedge the fair value of $75 million of our 7¹/4% 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.

we pay the counterparty an amount equal to the difference in rate times $75 million for the six month period. As of September 30, 2004, we have recorded a long term derivative asset of $1.7 million related to the interest rate swap, which has been designated as a fair value hedge, with a corresponding debt increase.

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 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 September 30, 2004. Based upon their evaluation of these disclosures controls and procedures, the Chairman, President and Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the end of the quarter ended September 30, 2004 to ensure that material information relating to us, including our consolidated subsidiaries, was made known to them by others within those entities, particularly during the period in which this Quarterly Report on Form 10-Q was being prepared.

Changes in internal control over financial reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended September 30, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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

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 18th day of October, 2004.


WHITING PETROLEUM CORPORATION

By		/S/ JAMES J. VOLKER
		James J. Volker
		Chairman, President and Chief Executive Officer

By		/S/ JAMES R. CASPERSON
		James R. Casperson
		Vice President and Chief Financial Officer



PART I

Item 1.	Financial Statements	1

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32

Item 4.	Controls and Procedures	35

PART II

Item 6.	Exhibits	35



Consolidated Balance Sheets as of September 30, 2004 (Unaudited) and December 31, 2003		2

Unaudited Consolidated Statements of Income for the Three Months and Nine Months Ended September 30, 2004 and 2003		4

Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the Year Ended December 31, 2003 and the Nine Months Ended September 30, 2004 (Unaudited)		5

Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2004 and 2003		6

Notes to Unaudited Consolidated Financial Statements		7


	September 30, 2004			December 31, 2003
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	17,361		$	53,585
Accounts receivable trade, net		35,322			24,020
Prepaid expenses and other		6,488			2,666

Total current assets		59,171			80,271

PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties		1,193,090			615,764
Unproved properties		4,325			1,637
Other property and equipment		3,616			2,684

Total property and equipment		1,201,031			620,085

Less accumulated depreciation, depletion and amortization		(225,275	)		(192,794	)


Total property and equipment-net		975,756			427,291

OTHER LONG-TERM ASSETS		19,624			9,988

DEFERRED INCOME TAX ASSET		—			18,735

TOTAL	$	1,054,551		$	536,285


	September 30, 2004			December 31, 2003
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	23,280		$	15,918
Oil and gas sales payable		4,051			2,406
Accrued employee benefits		4,788			5,275
Production taxes payable		7,580			2,574
Derivative liability		9,850			2,145
Income taxes and other liabilities		200			693
Current portion of long-term debt		50,000			—

Total current liabilities		99,749			29,011

ASSET RETIREMENT OBLIGATIONS		30,502			23,021

PRODUCTION PARTICIPATION PLAN LIABILITY		8,833			7,868

TAX SHARING LIABILITY		30,590			28,790

LONG-TERM DEBT		538,827			188,017

DEFERRED INCOME TAX LIABILITY		11,153			—

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY:
Common stock, $.001 par value; 75,000,000 shares authorized, 21,100,347 and 18,750,000 shares issued and outstanding		21			19
Additional paid-in capital		216,120			170,367
Accumulated other comprehensive loss		(6,050	)		(223	)
Deferred compensation		(2,035	)		—
Retained earnings		126,841			89,415

Total stockholders’ equity		334,897			259,578

TOTAL	$	1,054,551		$	536,285


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
REVENUES:
Oil and gas sales	$	65,898		$	42,272		$	166,408		$	133,638
Loss on oil and gas hedging activities		(2,040	)		(151	)		(3,615	)		(8,953	)
Gain on sale of marketable securities		2,380			—			4,762			—
Gain on sale of oil and gas properties		1,000			—			1,000			—
Interest income and other		52			87			186			180

Total		67,290			42,208			168,741			124,865

COSTS AND EXPENSES:
Lease operating		12,957			11,288			34,650			32,108
Production taxes		3,950			2,560			10,168			8,134
Depreciation, depletion and amortization		13,010			10,212			34,500			30,675
Exploration and impairment		3,766			280			4,686			1,015
General and administrative		6,117			3,126			14,191			9,522
Interest expense		4,172			1,856			9,591			7,110

Total costs and expenses		43,972			29,322			107,786			88,564

INCOME BEFORE INCOME TAXES AND CUMULATIVE CHANGE IN ACCOUNTING PRINCIPLE		23,318			12,886			60,955			36,301

INCOME TAX EXPENSE:
Current		400			208			400			650
Deferred		8,601			4,688			23,129			13,144

Total income tax expense		9,001			4,896			23,529			13,794

INCOME FROM CONTINUING OPERATIONS		14,317			7,990			37,426			22,507

CUMULATIVE CHANGE IN ACCOUNTING PRINCIPLE (See Note 4)		—			—			—			(3,905	)

NET INCOME	$	14,317		$	7,990		$	37,426		$	18,602

Earnings per share from continuing operations, basic and diluted	$	0.70		$	0.43		$	1.93		$	1.20
Cumulative change in accounting principle											(0.21	)

NET INCOME PER COMMON SHARE, BASIC AND DILUTED	$	0.70		$	0.43		$	1.93		$	0.99

WEIGHTED AVERAGE SHARES OUTSTANDING, BASIC		20,516			18,750			19,341			18,750

WEIGHTED AVERAGE SHARES OUTSTANDING, DILUTED		20,554			18,750			19,370			18,750

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	Common Stock			Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Deferred Compensation			Total Stockholders’ Equity			Comprehensive Income
	Shares	Amount		Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Deferred Compensation			Total Stockholders’ Equity			Comprehensive Income
BALANCES—January 1, 2003	18,750	$	19	$	53,219		$	71,130	$	(1,550	)	$	—		$	122,818
Net income								18,285								18,285		$	18,285
Unrealized net gain on marketable securities for sale										664						664			664
Change in derivative instrument fair value										663						663			663
Conversion of Alliant note payable to equity					80,931											80,931
Issuance of note payable					(3,000	)										(3,000	)
Phantom equity plan contribution					10,666											10,666
Tax basis step-up					28,551											28,551

BALANCES—December 31, 2003	18,750		19		170,367			89,415		(223	)		—			259,578		$	19,612

Net income (unaudited)								37,426								37,426		$	37,426
Change in fair value of marketable securities for sale (unaudited)										3,741						3,741			3,741
Realized net gain on marketable securities for sale (unaudited)										(4,835	)					(4,835	)		(4,835	)
Change in derivative instrument fair value (unaudited)										(4,733	)					(4,733	)		(4,733	)
Issuance of stock (unaudited)	2,237		2		43,296											43,298
Deferred compensation stock issued (unaudited)	113				2,457								(2,457	)
Amortization of deferred compensation (unaudited)													422			422

BALANCES—September 30, 2004 (unaudited)	21,100	$	21	$	216,120		$	126,841	$	(6,050	)	$	(2,035	)	$	334,897		$	31,599


	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	37,426		$	18,601
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		34,500			30,674
Deferred income taxes		23,129			13,144
Amortization of debt issuance costs and debt discount		1,025			860
Accretion of tax sharing agreement		1,800			—
Amortization of deferred compensation		422			—
Gain on sale of marketable securities		(4,835	)		—
Gain on sale of oil and gas properties		(1,000	)		—
Impairment of oil and gas properties		2,152			—
Cumulative change in accounting principle		—			3,905
Changes in assets and liabilities:
Accounts receivable		(6,466	)		1,018
Income taxes and other receivable		—			204
Other assets		(3,652	)		1,452
Asset retirement obligations		(321	)		(128	)
Production participation plan liability		542			(650	)
Other current liabilities		12,144			5,874

Net cash provided by operating activities		96,866			74,954

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash acquisition capital expenditures		(445,340	)		(6,466	)
Drilling capital expenditures		(52,782	)		(26,603	)
Proceeds from sale of marketable securities		5,420			—
Proceeds from sale of oil and gas properties		1,000			—
Equity Oil Company cash paid in excess of cash received		(256	)
Acquisition of partnership interests, net of cash received		—			(4,453	)

Net cash used by investing activities		(491,958	)		(37,522	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Advances from Alliant		—			460
Issuance of long-term debt		583,890
Payments on long-term debt		(214,000	)
Debt issuance costs		(11,022	)		(218	)

Net cash provided (used) by financing activities		358,868			242

NET CHANGE IN CASH AND CASH EQUIVALENTS		(36,224	)		37,674
CASH AND CASH EQUIVALENTS:
Beginning of period		53,585			4,833

End of period	$	17,361		$	42,507

SUPPLEMENT CASH FLOW DISCLOSURES:
Cash paid for income taxes	$	885		$	446

Cash paid for interest	$	3,592		$	5,726

NONCASH FINANCING ACTIVITIES:
Issuance of common stock for Equity Oil Company common stock	$	43,298			—

Alliant debt converted to equity	$	—		$	80,931


	Nine Months Ended September 30, 2004			Year Ended December 31, 2003
Beginning asset retirement obligation	$	23,021		$	4,232
SFAS 143 adoption		—			16,458
Additional liability incurred		6,588			996
Accretion expense		1,214			1,482
Liabilities settled		(321	)		(147	)

Ending asset retirement obligation	$	30,502		$	23,021


	September 30, 2004			December 31, 2003
7¼% Senior Subordinated Notes due 2012	$	150,697		$	—
Credit Facility	$	435,000		$	185,000
Alliant	$	3,130		$	3,017

Total debt	$	588,827		$	188,017
Less current portion of long-term debt	$	(50,000	)	$	—

Long-term debt	$	538,827		$	188,017


	Permian Basin		Equity Oil			Other Cash Acquisitions
Purchase Price:
Cash paid, net of cash received	$	345,000	$	256		$	98,500
Debt assumed				29,000
Stock issued				43,298

Total	$	345,000	$	72,554		$	98,500

Allocation of Purchase Price:
Working capital			$	3,779
Oil and gas properties	$	345,000		82,776		$	98,500
Deferred income taxes				(10,418	)
Other non-current liabilities				(3,583	)

Total	$	345,000	$	72,554		$	98,500


			Pro Forma
	Historical Whiting		Permian Basin		Equity Oil		Other Cash Acquisitions		Pro Forma Consolidated
Year ended December 31, 2003
Total revenues	$	167,381	$	91,246	$	27,825	$	28,592	$	315,044
Net income from continuing operations		22,190		19,028		6,050		3,823		51,091
Net income		18,285		19,028		6,050		3,823		47,186
Net income per common share-basic and diluted		0.98		0.91		0.29		0.18		2.25

Three months ended September 30, 2004
Total revenues	$	67,290	$	19,300	$	1,489	$	6,123	$	94,202
Net income		14,317		4,649		377		1,205		20,548
Net income per common share-basic and diluted		0.70		0.22		0.02		0.06		0.98

Three months ended September 30, 2003
Total revenues	$	42,208	$	21,476	$	6,705	$	7,117	$	77,506
Net income		7,990		4,733		1,408		955		15,086
Net income per common share-basic and diluted		0.43		0.23		0.07		0.05		0.72


	Three Months Ended
	March 31, 2004		June 30, 2004		September 30, 2004
Nine months ended September 30, 2004:
Oil and gas sales	$	47,636	$	52,874	$	65,898
Net income		9,638		13,471		14,317
Basic net income per share		0.51		0.72		0.70


	Nine Months Ended September 30,
	2004		2003
Depletion	$	32,736	$	29,011
Depreciation		550		560
Accretion of asset retirement obligations		1,214		1,104

Total	$	34,500	$	30,675


	Three Months Ended September 30,
	2004		2003
Depletion	$	12,366	$	9,635
Depreciation		190		200
Accretion of asset retirement obligations		454		377

Total	$	13,010	$	10,212


	Payments due by period
Contractual Obligations	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
Long-Term Debt	$	588.8	$	50.0	$	3.1	$	385.0	$	150.7
Operating Lease		5.7		0.9		1.8		1.8		1.2
Tax Separation and Indemnification Agreement with Alliant Energy(1)		30.6		—		4.2		3.1		23.3

Total	$	625.1	$	50.9	$	9.1	$	389.9	$	175.2


Commodity	Period	Monthly Volume (MMBtu)/(Bbl)	NYMEX Floor/Ceiling
Natural Gas	10/2004 to 12/2004	400,000	4.50/9.40
Natural Gas	10/2004 to 12/2004	400,000	4.50/12.00
Natural Gas	10/2004 to 12/2004	650,000	4.50/8.75
Natural Gas	01/2005 to 03/2005	400,000	5.00/12.75
Natural Gas	01/2005 to 03/2005	500,000	5.00/11.00
Natural Gas	01/2005 to 03/2005	600,000	5.00/10.50
Natural Gas	04/2005 to 06/2005	1,500,000	4.50/8.25
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
Crude Oil	10/2004 to 12/2004	50,000	28.00/46.10
Crude Oil	10/2004 to 12/2004	50,000	30.00/48.50
Crude Oil	10/2004 to 12/2004	44,000	35.00/51.90
Crude Oil	10/2004 to 12/2004	120,000	37.00/49.10
Crude Oil	10/2004 to 12/2004	50,000	37.00/54.75
Crude Oil	01/2005 to 03/2005	50,000	35.00/50.75
Crude Oil	01/2005 to 03/2005	94,000	35.00/49.60
Crude Oil	01/2005 to 03/2005	120,000	37.00/46.90
Crude Oil	01/2005 to 03/2005	80,000	37.00/50.60
Crude Oil	04/2005 to 06/2005	250,000	37.00/46.65
Crude Oil	07/2005 to 09/2005	250,000	35.00/47.25


Commodity	Period	Monthly Volume (MMBtu)	2004 Price Per MMBtu
Natural Gas	01/2002 to 12/2011	51,000	$	4.22
Natural Gas	01/2002 to 12/2012	60,000	$	3.74


Hedges and Contracts Summary	Hedged and Contracted (MMBtu)/(Bbl) per Month	As a Percentage of Estimated October 2004 Production (Gas/Oil)
October – December 2004	1,561,000/314,000	56%/69%
January – March 2005	1,611,000/344,000	58%/75%
April – June 2005	1,611,000/250,000	58%/55%
July – September 2005	1,611,000/250,000	58%/55%
October – December 2005	1,611,000/-0-	58%/-0-
Thereafter	111,000/ -0-	4%/ -0-


Exhibit Number		Exhibit Description
(2.1)		Agreement of Sale and Purchase, dated September 1, 2004, by and among Whiting Oil and Gas Corporation, CQ Acquisition Partners I, LP., SPA-CQAP II, LP, EnerQuest Oil & Gas, Ltd and Baytech, L.L.P. [Incorporated by reference to Exhibit 2 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 1, 2004 (File No. 001-31899)].

(4.1)		Second Amended and Restated Credit Agreement, dated as of September 23, 2004, among Whiting Oil and Gas Corporation, Whiting Petroleum Corporation, the financial institutions listed therein and Bank One, NA, as Administrative Agent [Incorporated by reference to Exhibit 4 to Whiting Petroleum Corporation’s Current Report on Form 8-K dated September 23, 2004 (File No. 001-31899)].

(10.1)		Form of Restricted Stock Agreement pursuant to Whiting Petroleum Corporation 2003 Equity Incentive Plan.

(31.1)		Certification by Chairman, President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

(31.2)		Certification by the 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 Chief Financial Officer pursuant to 18 U.S.C. Section 1350.